Timing is everything for investors looking to add natural gas stocks to their portfolios.
With wintry weather settling over most of North America, analysts are cautiously optimistic that increased demand for the home-heating fuel will make it an attractive investment once again.
But prospective investors should hold off on making a move for now.
"It's going to take at least another heat-winter cycle to get things soaked up," said Bryan Gormley, the Canadian Gas Institute's director for policy and economics.
One nasty snowstorm isn't going to do it. The natural gas industry needs months of consistent chilly temperatures for there to be a price impact.
Since 2006, natural gas prices in North America have been dragged down by a surplus overhang resulting from two balmy winters and one tepid summer. Drilling activity plummeted in 2007 and is expected to continue dropping next year.
"The Canadian natural gas industry has been operating under very challenging economic conditions over the past couple of years," said Barry Munro of Ernst & Young's Global Oil and Gas Center.
But taking a longer-term view, though, Munro said he is "very bullish about the prospects for natural gas."
"If it stays cold throughout the rest of the winter and we get to a better level of balance around natural gas supplies, I think that you'll see a much more bullish outlook heading into the fall/winter of '08-'09."
While weather is the key factor affecting natural gas prices, it certainly isn't the only one.
One major "wild card" is the increasing use of liquefied natural gas, or LNG, Munro said. The gas is condensed into a liquid in ultra-cold temperatures, making it easier to store and transport.
Currently most LNG ends up in the already saturated North American marketplace. But in the future it will be easier to transport it to places where it can be sold for a much better price, Munro said.
Today natural gas can be sold for about $3 more per thousand cubic feet in Europe than in North America.
Investors should also look at developments south of the border before buying natural-gas related stocks. Ramped up drilling activity in the United States could offset the effects of Canadian production cuts.
Monday, December 31, 2007
Sunday, December 30, 2007
Novatek Number 2 in Russa for Natural Gas
Luxembourg's Bluebird Securities Saturday said it had acquired a 5.7 percent stake in Russia's second largest gas producer Novatek.
A company statement said it had bought the shares from the Cyprus-based SWGI Growth Fund but did not reveal the amount it had paid.
SWGI Growth Fund has thereby reduced its holding in Novatek from 19.9 percent to 14.24 percent, Russia's Interfax news agency said.
Russia's state-run Gazprom is the country's largest gas producer.
Last year, Novatek produced 28.7 billion cubic metres of natural gas and reached 100 billion cubic metres in cumulative natural gas production since starting natural gas production in 1998, according to a company statement.
It accounted for four percent of the country's total natural gas production in 2006.
A company statement said it had bought the shares from the Cyprus-based SWGI Growth Fund but did not reveal the amount it had paid.
SWGI Growth Fund has thereby reduced its holding in Novatek from 19.9 percent to 14.24 percent, Russia's Interfax news agency said.
Russia's state-run Gazprom is the country's largest gas producer.
Last year, Novatek produced 28.7 billion cubic metres of natural gas and reached 100 billion cubic metres in cumulative natural gas production since starting natural gas production in 1998, according to a company statement.
It accounted for four percent of the country's total natural gas production in 2006.
Saturday, December 29, 2007
Texas Supplies 29% of US Natural Gas
With 2007 production of 6.3 trillion cubic feet, Texas is meeting 29 percent of the country's demand for natural gas, according to the Texas Railroad Commission's Oil and Gas Division.
The RRC also reported Texas 2007 oil production at 337 million barrels of oil. The state had an average rig count of 872, representing nearly half -- about 48 percent -- of all active land rigs in the United States.
The commission's estimated final production for October 2007 is 28.2 million barrels of crude oil and 481.4 Mcf (thousand cubic feet) of gas.
Texas natural gas storage reported by the commission for November 2007 is 395.5 million Mcf, compared with 444.3 million Mcf in November 2006. The December 2007 gas storage estimate is 392.4 million Mcf.
The RRC set initial January 2008 natural gas production allowables for prorated fields in the state to meet market demand of 16.7 million Mcf.
In setting the initial January 2008 allowables, the commission used historical production figures from previous months, producers' demand forecasts for the coming month, and adjusted the figures based on well capability. The initial allowables will be adjusted after actual production for January 2008 is reported.
The RRC also reported Texas 2007 oil production at 337 million barrels of oil. The state had an average rig count of 872, representing nearly half -- about 48 percent -- of all active land rigs in the United States.
The commission's estimated final production for October 2007 is 28.2 million barrels of crude oil and 481.4 Mcf (thousand cubic feet) of gas.
Texas natural gas storage reported by the commission for November 2007 is 395.5 million Mcf, compared with 444.3 million Mcf in November 2006. The December 2007 gas storage estimate is 392.4 million Mcf.
The RRC set initial January 2008 natural gas production allowables for prorated fields in the state to meet market demand of 16.7 million Mcf.
In setting the initial January 2008 allowables, the commission used historical production figures from previous months, producers' demand forecasts for the coming month, and adjusted the figures based on well capability. The initial allowables will be adjusted after actual production for January 2008 is reported.
Friday, December 28, 2007
ONGC India Will Pump Gas Through March 2008 in South Bassein Field
GAIL (India) has urged Oil and Natural Gas Corporation (ONGC) to defer the shutdown of its largest gas field off Mumbai till March 2008 to enable power and fertilizer companies to achieve their yearly targets.
Official sources said ONGC planned to shutdown two production complexes at the Bassein field during January-February to hook-up new facilities. The closure could possibly lead to a fall in natural gas availability from 42 million standard cubic metres a day to 29-31 mscmd.
The sources said GAIL had written to the Petroleum and Natural Gas Ministry that it would have to cut gas supplies to power and fertilizer units by 30-55 per cent during the shutdown period.
Fuel supplies to other users would be cut by as much as 89 per cent. “We have requested ONGC to defer the shutdown keeping into account the concerns of end-user industries,” the letter stated. In a separate letter, GAIL Director (Marketing) B. C. Tripathi said the proposed shutdown fell in the last quarter of the financial year and this would adversely impact achievement targets of GAIL, power and fertilizer sectors. ONGC plans to shut the BPB process complex from January 1 to 25 and the BPA complex from February 14 to 28 to hook-up the South Bassein field and the Vasai East field to the production system.
The shutdown of the BPB facility will reduce gas output by 13.5 mscmd and the closure of the BPA facility to cut output by 11 mscmd. As against current production of 42 mscmd, gas supply is expected to be in the range of 29 to 31 mscmd during the shutdown period. ONGC has invested Rs. 2,937 crore in additional development of the South Bassein field and another Rs. 1,688 crore in the Vasai East field.
Official sources said ONGC planned to shutdown two production complexes at the Bassein field during January-February to hook-up new facilities. The closure could possibly lead to a fall in natural gas availability from 42 million standard cubic metres a day to 29-31 mscmd.
The sources said GAIL had written to the Petroleum and Natural Gas Ministry that it would have to cut gas supplies to power and fertilizer units by 30-55 per cent during the shutdown period.
Fuel supplies to other users would be cut by as much as 89 per cent. “We have requested ONGC to defer the shutdown keeping into account the concerns of end-user industries,” the letter stated. In a separate letter, GAIL Director (Marketing) B. C. Tripathi said the proposed shutdown fell in the last quarter of the financial year and this would adversely impact achievement targets of GAIL, power and fertilizer sectors. ONGC plans to shut the BPB process complex from January 1 to 25 and the BPA complex from February 14 to 28 to hook-up the South Bassein field and the Vasai East field to the production system.
The shutdown of the BPB facility will reduce gas output by 13.5 mscmd and the closure of the BPA facility to cut output by 11 mscmd. As against current production of 42 mscmd, gas supply is expected to be in the range of 29 to 31 mscmd during the shutdown period. ONGC has invested Rs. 2,937 crore in additional development of the South Bassein field and another Rs. 1,688 crore in the Vasai East field.
Thursday, December 27, 2007
Gazprom Capital Investments $20 Billion in 2008
MOSCOW, Dec 27 (Reuters) - Russia's gas export monopoly Gazprom (GAZP.MM: Quote, Profile, Research) will increase capital investment by 43 percent in 2008 to a record level of almost $20 billion as it speeds up development of Arctic fields and new pipelines.
Gazprom has prioritised equity investment over capital expenditures for several years because of massive new asset purchases despite investor criticism over inadequate new -production investment amid stagnant mature-field output in Siberia. On Thursday the world's largest gas producer said its state-controlled board had approved its capital investments, which will rise to a record of 479.4 billion roubles ($19.41 billion) in 2008 from 335.5 billion roubles in 2007 and 324.9 billion in 2006.
The capital investments will be equally split between gas production and transportation.
Long-term financial investment will fall by 48 percent to 230.7 billion roubles from a record of 443.86 billion in 2007 and 133.7 billion in 2006.
Capital investment will go toward the Bovanenkov and Kharasavei fields on the Arctic Yamal peninsula, the firm's next source of big gas output, and Shtokman on the Barents Sea.
More funds will also be invested in new pipelines to connect Yamal to the existing system of trunk pipelines, which also needs to be expanded, Gazprom said.
Gazprom's 2007 financial investments soared after the firm agreed to buy 50 percent in the Sakhalin-2 oil and gas project, previously led by Royal Dutch Shell (RDSa.L: Quote, Profile, Research), for $7.45 billion, and a controlling purchase of Moscow utility Mosenergo.
Next year Gazprom said it will have to buy 50 percent in state oil major Rosneft's (ROSN.MM: Quote, Profile, Research) unit Tomskneft, in a deal valued at $3.66 billion, and pay $625 million to further increase its stake in Belarus' national pipeline network.
The company said some of the financial investment will also go toward Sakhalin-2, its new Nord Stream pipeline to Germany and Shtokman, but gave no details
Gazprom has prioritised equity investment over capital expenditures for several years because of massive new asset purchases despite investor criticism over inadequate new -production investment amid stagnant mature-field output in Siberia. On Thursday the world's largest gas producer said its state-controlled board had approved its capital investments, which will rise to a record of 479.4 billion roubles ($19.41 billion) in 2008 from 335.5 billion roubles in 2007 and 324.9 billion in 2006.
The capital investments will be equally split between gas production and transportation.
Long-term financial investment will fall by 48 percent to 230.7 billion roubles from a record of 443.86 billion in 2007 and 133.7 billion in 2006.
Capital investment will go toward the Bovanenkov and Kharasavei fields on the Arctic Yamal peninsula, the firm's next source of big gas output, and Shtokman on the Barents Sea.
More funds will also be invested in new pipelines to connect Yamal to the existing system of trunk pipelines, which also needs to be expanded, Gazprom said.
Gazprom's 2007 financial investments soared after the firm agreed to buy 50 percent in the Sakhalin-2 oil and gas project, previously led by Royal Dutch Shell (RDSa.L: Quote, Profile, Research), for $7.45 billion, and a controlling purchase of Moscow utility Mosenergo.
Next year Gazprom said it will have to buy 50 percent in state oil major Rosneft's (ROSN.MM: Quote, Profile, Research) unit Tomskneft, in a deal valued at $3.66 billion, and pay $625 million to further increase its stake in Belarus' national pipeline network.
The company said some of the financial investment will also go toward Sakhalin-2, its new Nord Stream pipeline to Germany and Shtokman, but gave no details
Liquified Natural Gas Pricing Monitored Weekly in Canada
In an important sign of the times for the Canadian natural gas market, FirstEnergy Capital is now issuing weekly price updates about the global liquefied natural gas business.
Two years ago, when Canadian gas was exiting Alberta for America customers at more than $10 per thousand cubic feet, the about-to-burgeon LNG market was a cursory thought at best in most of the minds in downtown Calgary.
Now, as North American gas prices remain relatively low because of ample supplies of the commodity, LNG isn’t some abstract concept. Calgary producers suddenly realize they’ve got to compete against not only companies in the U.S. but sellers of natural gas around the world.
This was recently highlighted by EnCana Corp., Canada’s largest gas producer, whose CEO Randy Eresman said Alberta would have to “re-establish [the] competitiveness” of the province’s gas business. It is this sector that helps keep the treasury full, now under threat because of high costs, low prices and rising royalties—and ever-stiffer competition.
A year ago, gas producers in Calgary hoped low commodity prices, big supplies and full storage caverns were just a brief interlude that was rudely interrupting what had been a brilliant boom.
Then came this summer. Gas prices, unusually, were higher in North American than the United Kingdom and Japan—traditional destinations for LNG cargoes. So LNG poured into North America, helping fill available winter storage capacity for the second season in a row—likely ensuring no January-March boom in the price, even if the continent’s east coast goes through several deep freezes.
To make sense of it all, enter FirstEnergy, the Calgary-based independent brokerage founded in the early 1990s by a group of young bankers, including Murray Edwards. FirstEnergy does much of its business financing junior natural gas producers. Unlike the old days, the new competition to sell gas to Americans to heat their homes and fuel their factories starts in places like Trinidad, Qatar and Egypt.
Right now, FirstEnergy reports that imports of LNG in the U.S. is sitting at about a billion cubic feet a day, near a five-year low, a trend expected to continue through January. The figure is way down from a spike up to 4 billion cubic feet a day in the summer. That was the spike that helped fill storage for winter, keeping continental prices low.
LNG imports in the U.S. are low right now because the benchmark gas price in the country is at about $7 per thousand cubic feet (U.S.). By comparison, LNG producers selling their product in Asia can get as much as double that rate.
Canada exports about 10 billion cubic feet a day of gas to America. According to the Energy Information Administration, the U.S. imports roughly 20 per cent of its natural gas. For Canadians, the key stat is that the country is losing market share. In 2001, about 94 per cent of gas imported into the U.S. was Maple Leaf output. Last year that had fallen to 86 per cent—and fell to 75 per cent in July—before bouncing back towards 90 per cent in September.)
So, for Canadian producers, the hope is that LNG supplies continue go elsewhere and North America supplies will ebb (though they have been surprisingly strong in the U.S.).
Lower supplies stoke higher prices, good for struggling Calgary producers and their stocks (but bad news for all of us that heat our homes with gas). And if it’s a cold winter followed by a hot summer, that would be another factor that would push prices higher.
But hope is an effervescent thing to depend on in the hard world of business. With the boom of 2005 now a distant memory, and an unexpectedly difficult 2007, producers in Calgary are now stoic, some of whom are struggling to stay in business. The big world of LNG is just another in a stack of problems. Finding a way to reduce costs in Alberta will be the big challenge. The year ahead will certainly remain in the category of interesting times.
Postscript: (Natural gas has traditionally been a continental commodity, used near where it is produced. LNG emerged a number of decades ago but was only particularly relevant for countries such as Japan, which were without their own sources. Technology has improved, prices globally have risen and it looks like the LNG market in the next several years will become a global one. The gas at its source is supercooled to -160C, at which point it becomes a shippable liquid. The liquid is regasified at its destination and then moved onwards to customers by pipeline.
Two years ago, when Canadian gas was exiting Alberta for America customers at more than $10 per thousand cubic feet, the about-to-burgeon LNG market was a cursory thought at best in most of the minds in downtown Calgary.
Now, as North American gas prices remain relatively low because of ample supplies of the commodity, LNG isn’t some abstract concept. Calgary producers suddenly realize they’ve got to compete against not only companies in the U.S. but sellers of natural gas around the world.
This was recently highlighted by EnCana Corp., Canada’s largest gas producer, whose CEO Randy Eresman said Alberta would have to “re-establish [the] competitiveness” of the province’s gas business. It is this sector that helps keep the treasury full, now under threat because of high costs, low prices and rising royalties—and ever-stiffer competition.
A year ago, gas producers in Calgary hoped low commodity prices, big supplies and full storage caverns were just a brief interlude that was rudely interrupting what had been a brilliant boom.
Then came this summer. Gas prices, unusually, were higher in North American than the United Kingdom and Japan—traditional destinations for LNG cargoes. So LNG poured into North America, helping fill available winter storage capacity for the second season in a row—likely ensuring no January-March boom in the price, even if the continent’s east coast goes through several deep freezes.
To make sense of it all, enter FirstEnergy, the Calgary-based independent brokerage founded in the early 1990s by a group of young bankers, including Murray Edwards. FirstEnergy does much of its business financing junior natural gas producers. Unlike the old days, the new competition to sell gas to Americans to heat their homes and fuel their factories starts in places like Trinidad, Qatar and Egypt.
Right now, FirstEnergy reports that imports of LNG in the U.S. is sitting at about a billion cubic feet a day, near a five-year low, a trend expected to continue through January. The figure is way down from a spike up to 4 billion cubic feet a day in the summer. That was the spike that helped fill storage for winter, keeping continental prices low.
LNG imports in the U.S. are low right now because the benchmark gas price in the country is at about $7 per thousand cubic feet (U.S.). By comparison, LNG producers selling their product in Asia can get as much as double that rate.
Canada exports about 10 billion cubic feet a day of gas to America. According to the Energy Information Administration, the U.S. imports roughly 20 per cent of its natural gas. For Canadians, the key stat is that the country is losing market share. In 2001, about 94 per cent of gas imported into the U.S. was Maple Leaf output. Last year that had fallen to 86 per cent—and fell to 75 per cent in July—before bouncing back towards 90 per cent in September.)
So, for Canadian producers, the hope is that LNG supplies continue go elsewhere and North America supplies will ebb (though they have been surprisingly strong in the U.S.).
Lower supplies stoke higher prices, good for struggling Calgary producers and their stocks (but bad news for all of us that heat our homes with gas). And if it’s a cold winter followed by a hot summer, that would be another factor that would push prices higher.
But hope is an effervescent thing to depend on in the hard world of business. With the boom of 2005 now a distant memory, and an unexpectedly difficult 2007, producers in Calgary are now stoic, some of whom are struggling to stay in business. The big world of LNG is just another in a stack of problems. Finding a way to reduce costs in Alberta will be the big challenge. The year ahead will certainly remain in the category of interesting times.
Postscript: (Natural gas has traditionally been a continental commodity, used near where it is produced. LNG emerged a number of decades ago but was only particularly relevant for countries such as Japan, which were without their own sources. Technology has improved, prices globally have risen and it looks like the LNG market in the next several years will become a global one. The gas at its source is supercooled to -160C, at which point it becomes a shippable liquid. The liquid is regasified at its destination and then moved onwards to customers by pipeline.
Wednesday, December 26, 2007
China Encourages Foreign Investment in Natural Gas
China will encourage foreign investment in its energy sector and will continue to improve the environment for such investment, says a white paper published on Wednesday by the Information Office of the State Council.
China will improve external cooperation in the exploration and development of oil and natural gas resources, says the white paper, which is titled "China's Energy Conditions and Policies."
The paper stresses that China protects the legitimate rights and interests of foreign businesses that collaborate in oil exploitation.
The country encourages foreign businesses to participate in cooperative activities in oil exploration and development, such as risk exploration for oil and natural gas, low-permeability oil fields and gas reservoirs and the improvement of recovery rates of old oil fields, says the paper.
Foreign investment is also welcome in the construction and operation of oil and gas pipelines, as well as special oil and gas storage facilities and port berths, it says.
Exploration and development of unconventional energy resources, such as coalbed methane, is also open to foreign investment, it says.
"China allows foreign investors, either alone or in collaboration with Chinese counterparts, to conduct risk exploration on its territory," says the paper.
Foreign interests that invest in exploring and recovering paragenetic and associated minerals and utilizing tailing or exploring mineral resources in China's western regions "are entitled to enjoy the preferential policy of reduction of or exemption from mineral resources compensation fees", the paper says.
Paragenetic minerals are those mixed together in the same deposit, such as copper and gold.
The paper says further efforts are being made to improve management of and services to foreign investment in the exploration and production of mineral resources aside from oil and gas.
The country also encourages foreign investors to invest in and operate energy facilities such as power plants.
The scope of foreign investment will be expanded, the paper says.
In bringing in foreign investment for the development and utilization of energy resources, China focuses on several factors.
These include technology transfer, management experience and skilled staff to further shift the focus from investing in fossil energy resources to renewable resources.
China also wants to shift away from an emphasis on exploration and development to the development of service trade, and from reliance mainly on foreign loans and direct foreign investment to the directly pooling of funds in international capital market, the paper says
China will improve external cooperation in the exploration and development of oil and natural gas resources, says the white paper, which is titled "China's Energy Conditions and Policies."
The paper stresses that China protects the legitimate rights and interests of foreign businesses that collaborate in oil exploitation.
The country encourages foreign businesses to participate in cooperative activities in oil exploration and development, such as risk exploration for oil and natural gas, low-permeability oil fields and gas reservoirs and the improvement of recovery rates of old oil fields, says the paper.
Foreign investment is also welcome in the construction and operation of oil and gas pipelines, as well as special oil and gas storage facilities and port berths, it says.
Exploration and development of unconventional energy resources, such as coalbed methane, is also open to foreign investment, it says.
"China allows foreign investors, either alone or in collaboration with Chinese counterparts, to conduct risk exploration on its territory," says the paper.
Foreign interests that invest in exploring and recovering paragenetic and associated minerals and utilizing tailing or exploring mineral resources in China's western regions "are entitled to enjoy the preferential policy of reduction of or exemption from mineral resources compensation fees", the paper says.
Paragenetic minerals are those mixed together in the same deposit, such as copper and gold.
The paper says further efforts are being made to improve management of and services to foreign investment in the exploration and production of mineral resources aside from oil and gas.
The country also encourages foreign investors to invest in and operate energy facilities such as power plants.
The scope of foreign investment will be expanded, the paper says.
In bringing in foreign investment for the development and utilization of energy resources, China focuses on several factors.
These include technology transfer, management experience and skilled staff to further shift the focus from investing in fossil energy resources to renewable resources.
China also wants to shift away from an emphasis on exploration and development to the development of service trade, and from reliance mainly on foreign loans and direct foreign investment to the directly pooling of funds in international capital market, the paper says
Tuesday, December 25, 2007
LNG Could Surpass Oil as Energy Source if Price Remains High
Oil may be the energy source on everyone's mind right now, but there is a good chance that liquefied natural gas (LNG) will surpass it as oil prices remain astronomical.
Once a bit of a backwater in the energy field, demand for LNG has been on a steady rise because it is relatively clean burning and because its liquefied state allows for transport to remote locations without construction of elaborate and expensive pipeline networks.
And while it can't hold a candle to oil's price, quite a few analysts seem to see it as the bandwagon of choice to jump on to.
Worldwide demand for LNG during the first half of 2007 was pegged at roughly 115 billion cubic metres (bcm), roughly nine per cent growth over the same period in 2006, and demand in East Asia has been growing even faster.
Once a bit of a backwater in the energy field, demand for LNG has been on a steady rise because it is relatively clean burning and because its liquefied state allows for transport to remote locations without construction of elaborate and expensive pipeline networks.
And while it can't hold a candle to oil's price, quite a few analysts seem to see it as the bandwagon of choice to jump on to.
Worldwide demand for LNG during the first half of 2007 was pegged at roughly 115 billion cubic metres (bcm), roughly nine per cent growth over the same period in 2006, and demand in East Asia has been growing even faster.
Iran Looks for Natural Gas Deal with Italy
Iran is in talks with Italian power utility Edison (EDN.MI: Quote, Profile, Research) about exporting gas to the European Union country, Iranian Oil Minister Gholamhossein Nozari said on Sunday.
Iran sits atop the world's second largest gas reserves after Russia. But sanctions, politics and construction delays have slowed its gas development, and analysts say the country is unlikely to become a major exporter for a decade.
Soaring oil and gas prices have made energy supply an acute issue in Italy, which has scarce energy resources and depends on imports for about 80 percent of its energy needs.
"We have started negotiations ... and the talks have almost been finalized," Nozari said in comments aired by state television.
"Their preliminary need for the end of 2008 is 1.5 bcf (billion cubic feet) and it will be increased to 4.5 bcf," he said, without giving details.
Edison has said it aims to boost its natural gas supplies to more than 23 billion cubic meters (bcm) from the current level of 13 bcm thanks to its participation in major gas pipeline projects and a liquefied natural gas terminal project in Italy.
The United States, leading efforts to isolate Tehran over its disputed nuclear program, has urged international companies to avoid doing business with Iran, which is also the world's fourth-largest crude exporter.
Italy is one of Iran's largest trading partners and the head of Italian oil major Eni (ENI.MI: Quote, Profile, Research) said last month it will not abandon its contracts in the Islamic state.
Iran says its nuclear work is peaceful and aimed at generating electricity so that it can export more oil and gas. Its large gas reserves make it a magnet for international energy firms, despite two rounds of U.N. sanctions since December.
Iran sits atop the world's second largest gas reserves after Russia. But sanctions, politics and construction delays have slowed its gas development, and analysts say the country is unlikely to become a major exporter for a decade.
Soaring oil and gas prices have made energy supply an acute issue in Italy, which has scarce energy resources and depends on imports for about 80 percent of its energy needs.
"We have started negotiations ... and the talks have almost been finalized," Nozari said in comments aired by state television.
"Their preliminary need for the end of 2008 is 1.5 bcf (billion cubic feet) and it will be increased to 4.5 bcf," he said, without giving details.
Edison has said it aims to boost its natural gas supplies to more than 23 billion cubic meters (bcm) from the current level of 13 bcm thanks to its participation in major gas pipeline projects and a liquefied natural gas terminal project in Italy.
The United States, leading efforts to isolate Tehran over its disputed nuclear program, has urged international companies to avoid doing business with Iran, which is also the world's fourth-largest crude exporter.
Italy is one of Iran's largest trading partners and the head of Italian oil major Eni (ENI.MI: Quote, Profile, Research) said last month it will not abandon its contracts in the Islamic state.
Iran says its nuclear work is peaceful and aimed at generating electricity so that it can export more oil and gas. Its large gas reserves make it a magnet for international energy firms, despite two rounds of U.N. sanctions since December.
Monday, December 24, 2007
Alabama Shale is a Natural Gas Play for Energen Corp
Energen Corp. has acquired additional land for natural gas exploration in Alabama, but Chief Executive James McManus identified sites only in Bibb and Greene Counties.
"It's our stealth play," McManus said in an interview, talking about natural gas land in an unidentified Alabama location. "It is an area with very little competition. We are the only ones who know what we have."
It's part of a great land grab going on mostly in St. Clair County and farther north, where Energen and a unit of New York-based rival Loew's Corp. are trying to extract natural gas from underground shale formations. Loew's has 14 wells under some stage of development in St. Clair County.
"It's our stealth play," McManus said in an interview, talking about natural gas land in an unidentified Alabama location. "It is an area with very little competition. We are the only ones who know what we have."
It's part of a great land grab going on mostly in St. Clair County and farther north, where Energen and a unit of New York-based rival Loew's Corp. are trying to extract natural gas from underground shale formations. Loew's has 14 wells under some stage of development in St. Clair County.
Sunday, December 23, 2007
Kentucky Natural Gas Exploration Under Consideration
The Henderson City-County Air Board and Henderson County Riverport Authority are considering allowing an Evansville company to explore for natural gas under their respective properties.
But the boards would like assurances that the exploration will not cause any land subsidence or other potential land-use problems. Both boards oversee land located on Kentucky 136 West between Henderson and Geneva.
"I would anticipate that the board would take action in January and that is only if they are able to guarantee that there won't be subsidence issues or obstruction of runway activities," said Air Board Chairman Scott Miller.
The riverport wants to be sure that it doesn't do something that later could complicate its efforts to persuade industries to locate at the port.
The company seeking the leases, Mid-Central Land Services LLC, has been in business for more than 30 years, according to Nathan Perdue, its director of operations.
Interest in natural gas exploration in Western Kentucky has spiked in recent years, and more than 4 million acres have been leased around the Illinois basin, according to Mark Hughes of Henderson, a vice president of the Kentucky Oil and Gas Association.
"This company is just leasing up (mineral rights from) everybody across the countryside," Greg Pritchett, director of the riverport, said Thursday.
In making his presentation to the Air Board recently, Perdue said his company might drill sideways to the natural gas so there is no well on airport property.
He made similar remarks to the riverport board, Pritchett said.
If natural gas is discovered, the airport or riverport would receive a 12.5 percent royalty payment on the total amount of natural gas that is removed over a five-year lease. But no firm dollar figures were presented verbally to the air board. Miller said the amount of money the board would receive depends on the type of drilling method used.
Riverport officials aren't sure what the revenue potential is. The port has acquired various parcels of property over the years, and while it owns 100 percent of the mineral rights under some parcels, it controls rights only at certain depths underground beneath other parcels.
"There is a percentage chance of hitting" natural gas reserves underground, Pritchett said. "There is a bigger percentage of hitting nothing."
"If we do not have sufficient underground ownership, why even try" to lease its mineral reserves, he said.
But the boards would like assurances that the exploration will not cause any land subsidence or other potential land-use problems. Both boards oversee land located on Kentucky 136 West between Henderson and Geneva.
"I would anticipate that the board would take action in January and that is only if they are able to guarantee that there won't be subsidence issues or obstruction of runway activities," said Air Board Chairman Scott Miller.
The riverport wants to be sure that it doesn't do something that later could complicate its efforts to persuade industries to locate at the port.
The company seeking the leases, Mid-Central Land Services LLC, has been in business for more than 30 years, according to Nathan Perdue, its director of operations.
Interest in natural gas exploration in Western Kentucky has spiked in recent years, and more than 4 million acres have been leased around the Illinois basin, according to Mark Hughes of Henderson, a vice president of the Kentucky Oil and Gas Association.
"This company is just leasing up (mineral rights from) everybody across the countryside," Greg Pritchett, director of the riverport, said Thursday.
In making his presentation to the Air Board recently, Perdue said his company might drill sideways to the natural gas so there is no well on airport property.
He made similar remarks to the riverport board, Pritchett said.
If natural gas is discovered, the airport or riverport would receive a 12.5 percent royalty payment on the total amount of natural gas that is removed over a five-year lease. But no firm dollar figures were presented verbally to the air board. Miller said the amount of money the board would receive depends on the type of drilling method used.
Riverport officials aren't sure what the revenue potential is. The port has acquired various parcels of property over the years, and while it owns 100 percent of the mineral rights under some parcels, it controls rights only at certain depths underground beneath other parcels.
"There is a percentage chance of hitting" natural gas reserves underground, Pritchett said. "There is a bigger percentage of hitting nothing."
"If we do not have sufficient underground ownership, why even try" to lease its mineral reserves, he said.
India Oil & Gas Spending for Natural Gas
Oil & Natural Gas Corp., India's biggest explorer, will boost spending to increase output at its biggest field and pay a mid-year dividend of 18 rupees a share.
The New Delhi-based company will spend an additional 25.5 billion rupees ($645 million) on increasing production at its Mumbai High area off India's west coast, Oil & Natural Gas said in an e-mailed statement. The explorer's board also approved the dividend payment amounting to 38.5 billion rupees.
Oil & Natural Gas, which in October approved a $1.4 billion investment on the acreage, needs to increase output to retain its position as the largest supplier of crude oil and gas in India. Oil imports by India, Asia's third-biggest oil consumer after China and Japan, are set to rise as refiners expand capacity to meet demand. India imports three-fourths of its oil requirement.
The Mumbai High region yields about 16 million tons of crude oil annually, or 320,000 barrels a day, which is more than 60 percent of the company's total output.
The explorer is investing in upgrading platforms and digging deeper wells and plans to replace pipelines as output from the aging, nearly three-decade old, area declines.
Oil & Natural Gas's spending, approved yesterday, will go toward replacing a network of pipelines, the company said. The money will be spent over three years.
The board also approved spending 1.5 billion rupees on the PY-3 field in the Cauvery basin, off the east coast. Oil & Natural Gas holds a 40 percent stake in the area, and Hindustan Oil Exploration Co. and Tata Petrodyne Ltd. hold 21 percent each.
Oil & Natural Gas plans to boost spending on developing new and existing fields by 20 percent in the year that began April 1 to 180 billion rupees from 150 billion rupees the previous year, Chairman R.S. Sharma said on April 16.
The New Delhi-based company will spend an additional 25.5 billion rupees ($645 million) on increasing production at its Mumbai High area off India's west coast, Oil & Natural Gas said in an e-mailed statement. The explorer's board also approved the dividend payment amounting to 38.5 billion rupees.
Oil & Natural Gas, which in October approved a $1.4 billion investment on the acreage, needs to increase output to retain its position as the largest supplier of crude oil and gas in India. Oil imports by India, Asia's third-biggest oil consumer after China and Japan, are set to rise as refiners expand capacity to meet demand. India imports three-fourths of its oil requirement.
The Mumbai High region yields about 16 million tons of crude oil annually, or 320,000 barrels a day, which is more than 60 percent of the company's total output.
The explorer is investing in upgrading platforms and digging deeper wells and plans to replace pipelines as output from the aging, nearly three-decade old, area declines.
Oil & Natural Gas's spending, approved yesterday, will go toward replacing a network of pipelines, the company said. The money will be spent over three years.
The board also approved spending 1.5 billion rupees on the PY-3 field in the Cauvery basin, off the east coast. Oil & Natural Gas holds a 40 percent stake in the area, and Hindustan Oil Exploration Co. and Tata Petrodyne Ltd. hold 21 percent each.
Oil & Natural Gas plans to boost spending on developing new and existing fields by 20 percent in the year that began April 1 to 180 billion rupees from 150 billion rupees the previous year, Chairman R.S. Sharma said on April 16.
Saturday, December 22, 2007
Big Three Still Forming Canada Gas Corporation for Natural Gas
VANCOUVER, British Columbia, Dec 21, 2007 (BUSINESS WIRE) -- Bighorn Petroleum Ltd. (TSX VENTURE: BHP) ("Bighorn"), Flying A Petroleum Ltd. (TSX VENTURE: FAB) ("Flying A"), Tenaka Drilling Consortium Ltd. ("Tenaka") and Wyn Developments Inc. (TSX VENTURE: WL) (FWB: YXE) (OTCBB: WYDPF) ("Wyn"), (collectively the "Partners"), continue efforts to complete the amalgamation into Canada Gas Corp. (the "Company") as soon as possible. Recent efforts have concentrated on financing the Company to meet near term commitments, which include both drilling and acquisition. Focus Energy Trust has now drilled the first well of the 2007/2008 winter season, the a-38-A/94-G-15 Triassic Halfway development well at Bougie Trutch. The well is now undergoing testing and completion and upon success, will be tied into production prior to the end of the 2007/2008 winter drill season (Q1 2008).
Wyn Developments Inc. and Flying A Petroleum Ltd. announce that they have each entered into bridge loan agreements with a third party investor for the total loan sum of $200,000, subject to regulatory approval where required. Pursuant to the Wyn bridge loan agreement, the lender agreed to lend a total of $92,000 to Wyn. Wyn has agreed to issue the lender 92,000 of its common shares as a bonus at a deemed price of $0.10 per share, issuable upon receipt of regulatory acceptance of the Wyn bridge loan agreement. Pursuant to the Flying A bridge loan agreement, the lender agreed to lend a total of $108,000 to Flying A. Flying A agreed to issue 108,000 of its common shares to the lender as a bonus at a deemed price of $0.10 per share, issuable upon receipt of regulatory acceptance of the Flying A bridge loan agreement. The Wyn and Flying A loans are repayable upon the earlier of the completion of an equity financing by Canada Gas Corp. (the merged entity) and April 30, 2008. The bridge loans bear interest at 12% per annum.
Discussions are ongoing among the Partners with a number of interested investor groups respecting the form and terms of an equity financing for Canada Gas Corp, however, the Partners will now finalize the share exchange ratios and seek conditional Toronto Venture Exchange acceptance of the transaction. The shareholder information circulars outlining the entire transaction with prospectus level disclosure will be distributed as soon as possible thereafter, ahead of shareholder meetings to be scheduled at least 25 days from mailing. After the meetings, the Partners will require court and final Exchange approval prior to the Company being called to trade.
Wyn Developments Inc. and Flying A Petroleum Ltd. announce that they have each entered into bridge loan agreements with a third party investor for the total loan sum of $200,000, subject to regulatory approval where required. Pursuant to the Wyn bridge loan agreement, the lender agreed to lend a total of $92,000 to Wyn. Wyn has agreed to issue the lender 92,000 of its common shares as a bonus at a deemed price of $0.10 per share, issuable upon receipt of regulatory acceptance of the Wyn bridge loan agreement. Pursuant to the Flying A bridge loan agreement, the lender agreed to lend a total of $108,000 to Flying A. Flying A agreed to issue 108,000 of its common shares to the lender as a bonus at a deemed price of $0.10 per share, issuable upon receipt of regulatory acceptance of the Flying A bridge loan agreement. The Wyn and Flying A loans are repayable upon the earlier of the completion of an equity financing by Canada Gas Corp. (the merged entity) and April 30, 2008. The bridge loans bear interest at 12% per annum.
Discussions are ongoing among the Partners with a number of interested investor groups respecting the form and terms of an equity financing for Canada Gas Corp, however, the Partners will now finalize the share exchange ratios and seek conditional Toronto Venture Exchange acceptance of the transaction. The shareholder information circulars outlining the entire transaction with prospectus level disclosure will be distributed as soon as possible thereafter, ahead of shareholder meetings to be scheduled at least 25 days from mailing. After the meetings, the Partners will require court and final Exchange approval prior to the Company being called to trade.
Friday, December 21, 2007
Magnum Finds Natural Gas in Canada
VANCOUVER, BRITISH COLUMBIA, Dec 20, 2007 (Marketwire via COMTEX) -- Magnum Energy Inc. ("The Company") (TSX VENTURE:MEN) is pleased to announce the test results of the recent fracture and flow test of the Cardium exploration well. Initial test rates in excess of 600 barrels/d of sweet light oil and approximately 200 Mcf/d of natural gas were reported by the operator.
According to EUB regulations the operator can only flare the natural gas for 72 hours. The operator has now shut the well in until it is equipped and tied in for both oil and gas production. This is expected to be completed early in 2008.
The operator has also made an application to the EUB for GPP (Good Production Practices) approval in order to produce the well to its maximum potential. Until the operator receives the approval, which usually takes about 30 days, the well will be restricted to 120 barrels of oil/d.
Magnum Energy Inc.
Magnum Energy Inc. is a junior oil and gas exploration company operating in the Western Canadian Sedimentary Basin. The company is headed by Ted Konyi, CEO who has had extensive experience in the financing of oil and gas projects in Western Canada. The company has established an initial core area in South Eastern Alberta which it believes will produce significant cash flow for the company upon completion of a comprehensive drilling program.
According to EUB regulations the operator can only flare the natural gas for 72 hours. The operator has now shut the well in until it is equipped and tied in for both oil and gas production. This is expected to be completed early in 2008.
The operator has also made an application to the EUB for GPP (Good Production Practices) approval in order to produce the well to its maximum potential. Until the operator receives the approval, which usually takes about 30 days, the well will be restricted to 120 barrels of oil/d.
Magnum Energy Inc.
Magnum Energy Inc. is a junior oil and gas exploration company operating in the Western Canadian Sedimentary Basin. The company is headed by Ted Konyi, CEO who has had extensive experience in the financing of oil and gas projects in Western Canada. The company has established an initial core area in South Eastern Alberta which it believes will produce significant cash flow for the company upon completion of a comprehensive drilling program.
Thursday, December 20, 2007
LNG Terminal for Netherlands in 2011
Dutch natural gas company Gasunie and tanker storage firm Vopak will go ahead with a 800-million-euro (around 1.12 billion U.S. dollars) investment to build the country's first liquefied gas terminal, Dutch media reported Wednesday.
The two companies announced the decision on Tuesday. The terminal will be located in Rotterdam, the biggest port in Europe. The construction of the terminal means that natural gas can be imported by ships in the future.
Currently, natural gas can only be transported to the Netherlands via pipeline from Norway and Russia.
The terminal, which is due to be operational in 2011, will make it possible to import gas from North Africa and the Middle East.
The two companies announced the decision on Tuesday. The terminal will be located in Rotterdam, the biggest port in Europe. The construction of the terminal means that natural gas can be imported by ships in the future.
Currently, natural gas can only be transported to the Netherlands via pipeline from Norway and Russia.
The terminal, which is due to be operational in 2011, will make it possible to import gas from North Africa and the Middle East.
Wednesday, December 19, 2007
1 Barrel of Oil Equals 6,000 Cubic Feet of Gas
TransGlobe Energy Corporation (TSX: TGL) (AMEX: TGA) ("TransGlobe" or the "Company") is announcing a mid-quarter production and operating update. All dollar values are expressed in United States dollars unless otherwise stated. Conversion of natural gas to oil is made on the basis of 6,000 cubic feet of natural gas being equivalent to one barrel of crude oil.
Production Summary
The Company's total production is expected to average approximately 7,000 Boepd during the fourth quarter of 2007. This represents a 34% increase over the third quarter of 2007 due to the addition of the West Gharib producing assets in Egypt.
Dated Brent oil prices were very strong averaging $82.50 per barrel in October and $92.61 during November, averaging 17% higher than the third quarter of 2007. North American natural gas prices showed continued weakness, averaging approximately C$6.00/Mcf during October/November. TransGlobe's production is 85% oil and natural gas liquids and 15% natural gas, mitigating the Company's sensitivity to gas pricing.
Production Summary
The Company's total production is expected to average approximately 7,000 Boepd during the fourth quarter of 2007. This represents a 34% increase over the third quarter of 2007 due to the addition of the West Gharib producing assets in Egypt.
Dated Brent oil prices were very strong averaging $82.50 per barrel in October and $92.61 during November, averaging 17% higher than the third quarter of 2007. North American natural gas prices showed continued weakness, averaging approximately C$6.00/Mcf during October/November. TransGlobe's production is 85% oil and natural gas liquids and 15% natural gas, mitigating the Company's sensitivity to gas pricing.
Tuesday, December 18, 2007
Chevron Natural Gas to Grow in Thailand
Chevron Thailand Exploration and Production, Ltd. (Chevron) and its co-concessionaires today signed a Gas Sales Agreement (GSA) with PTT Public Company Limited (PTT) for blocks 10-13 in the Gulf of Thailand. The agreement is expected to boost natural gas supplies from these blocks by 500 million cubic feet of natural gas per day (mmcf/d) or from a daily contract quantity of 740 million cubic feet mmcf/d in 2007 to 1,240 mmcf/d from 2012.
The offshore blocks represent nearly 50 percent of Chevron's current operating areas in the Pattani Basin and include Erawan, Satun, Funan, Baanpot, Jakrawan, Plamuk, Yala, Pla Daeng, Trat and Platong operating areas in the Gulf of Thailand. Chevron has working interests in the operating areas within these blocks ranging from 60 percent to 80 percent.
The signing in Bangkok was presided over by His Excellency Dr. Kurujit Nakornthap, Deputy Permanent Secretary and included Tara Tiradnakorn, president of Chevron Thailand Exploration and Production, Ltd., Prasert Bunsunpun, president of PTT, Yoshiyuki Kagawa, president and CEO of Mitsui Oil Exploration Ltd. (MOECO), and Maroot Mrigadat president of PTT Exploration and Production Public Company Limited. (PTTEP).
Speaking at the signing ceremony, President of Chevron Thailand Exploration and Production, Khun Tara Tiradnakorn, said: "Today's signing builds on our 45-year relationship between Chevron and the Kingdom of Thailand in working together to deliver clean, competitive energy supplies to fuel the country's growing economy. We are extremely proud to have been a long term partner with the Kingdom and look forward to continuing to strengthen this relationship well into the next decade."
"This agreement paves the way for Chevron and its partners to boost production from the Gulf of Thailand and to work together to provide reliable natural gas supplies for use mainly in power generation but also in the industrial and transportation sectors and the petrochemical industry," said Tiradnakorn.
"Natural gas is one of the fastest growing segments of Chevron's portfolio," said Managing Director and CEO of Chevron Asia South Ltd., Steve Green. Adding that, "Chevron's natural gas production is currently used to produce approximately one third of Thailand's total electricity demand and this is expected to increase to 40 percent once peak production is achieved from 2012."
The main source of this increased supply is a planned 330 mmcf/d expansion of the Platong field, including a new central processing platform (CPP), as well as an additional 170 mmcf/d from existing platforms.
This agreement follows the recently announced production period extension for blocks 10-13 for an additional ten years, from 2012 to 2022. Chevron's co- concessionaires in the blocks include MOECO and PTTEP.
Chevron operates more than 180 platforms in the Gulf of Thailand with 2006 total average daily production of more than 144,000 barrels of oil and condensate (73,000 net) and 1.6 billion gross cubic feet of gas (856 million net). Historically, the company and its joint venture partners have invested more than 12 billion US dollars in Thailand's oil and gas sector and paid the cumulative royalty of nearly 3.5 billion US dollars (1981 - 2006).
Chevron Corporation is one of the world's leading integrated energy companies. We have approximately 58,000 employees, and our subsidiaries conduct business across the entire energy spectrum - exploring for, producing and transporting crude oil and natural gas; refining, marketing and distributing fuels and other energy products and services; manufacturing and selling petrochemical products; generating power; and developing and commercializing the energy resources of the future, including biofuels and other renewables. Chevron is based in San Ramon, Calif. More information about Chevron is available at www.chevron.com.
The offshore blocks represent nearly 50 percent of Chevron's current operating areas in the Pattani Basin and include Erawan, Satun, Funan, Baanpot, Jakrawan, Plamuk, Yala, Pla Daeng, Trat and Platong operating areas in the Gulf of Thailand. Chevron has working interests in the operating areas within these blocks ranging from 60 percent to 80 percent.
The signing in Bangkok was presided over by His Excellency Dr. Kurujit Nakornthap, Deputy Permanent Secretary and included Tara Tiradnakorn, president of Chevron Thailand Exploration and Production, Ltd., Prasert Bunsunpun, president of PTT, Yoshiyuki Kagawa, president and CEO of Mitsui Oil Exploration Ltd. (MOECO), and Maroot Mrigadat president of PTT Exploration and Production Public Company Limited. (PTTEP).
Speaking at the signing ceremony, President of Chevron Thailand Exploration and Production, Khun Tara Tiradnakorn, said: "Today's signing builds on our 45-year relationship between Chevron and the Kingdom of Thailand in working together to deliver clean, competitive energy supplies to fuel the country's growing economy. We are extremely proud to have been a long term partner with the Kingdom and look forward to continuing to strengthen this relationship well into the next decade."
"This agreement paves the way for Chevron and its partners to boost production from the Gulf of Thailand and to work together to provide reliable natural gas supplies for use mainly in power generation but also in the industrial and transportation sectors and the petrochemical industry," said Tiradnakorn.
"Natural gas is one of the fastest growing segments of Chevron's portfolio," said Managing Director and CEO of Chevron Asia South Ltd., Steve Green. Adding that, "Chevron's natural gas production is currently used to produce approximately one third of Thailand's total electricity demand and this is expected to increase to 40 percent once peak production is achieved from 2012."
The main source of this increased supply is a planned 330 mmcf/d expansion of the Platong field, including a new central processing platform (CPP), as well as an additional 170 mmcf/d from existing platforms.
This agreement follows the recently announced production period extension for blocks 10-13 for an additional ten years, from 2012 to 2022. Chevron's co- concessionaires in the blocks include MOECO and PTTEP.
Chevron operates more than 180 platforms in the Gulf of Thailand with 2006 total average daily production of more than 144,000 barrels of oil and condensate (73,000 net) and 1.6 billion gross cubic feet of gas (856 million net). Historically, the company and its joint venture partners have invested more than 12 billion US dollars in Thailand's oil and gas sector and paid the cumulative royalty of nearly 3.5 billion US dollars (1981 - 2006).
Chevron Corporation is one of the world's leading integrated energy companies. We have approximately 58,000 employees, and our subsidiaries conduct business across the entire energy spectrum - exploring for, producing and transporting crude oil and natural gas; refining, marketing and distributing fuels and other energy products and services; manufacturing and selling petrochemical products; generating power; and developing and commercializing the energy resources of the future, including biofuels and other renewables. Chevron is based in San Ramon, Calif. More information about Chevron is available at www.chevron.com.
Monday, December 17, 2007
European Natural Gas Providers - Gazprom & Sonatrach
A natural-gas cooperation pact between Algeria’s Sonatrach energy group and Russia’s gazprom has lapsed and will not be renewed for the time being as a result of diverging views on strategy adopted, of late, by the two sides
In remarks made to the press in Algiers, Sonatrach’s CEO Mohamed Meziane said that a 2006 memorandum of understanding, Sonatrach signed with Russia's Gazprom OAO, had resulted in "nothing concrete" and ended a few months ago.
The lapse of the pact could calm fears in Europe that two of its largest natural gas suppliers could collaborate to drive prices higher.
In the interview, Mohamed Meziane was quoted as saying that the agreement was not about manipulating prices stressing that Sonatrach had opted to shift its LNG strategy in view of the latest developments notably on the European market.
Instead, he told reporters he had hoped the accord would lead to bilateral cooperation on liquefied natural gas.
Representatives from Gazprom in Moscow later confirmed the termination of the Algerian-Russian natural gas cooperation pact saying the two sides have, now, differing approaches on the matter.
In remarks made to the press in Algiers, Sonatrach’s CEO Mohamed Meziane said that a 2006 memorandum of understanding, Sonatrach signed with Russia's Gazprom OAO, had resulted in "nothing concrete" and ended a few months ago.
The lapse of the pact could calm fears in Europe that two of its largest natural gas suppliers could collaborate to drive prices higher.
In the interview, Mohamed Meziane was quoted as saying that the agreement was not about manipulating prices stressing that Sonatrach had opted to shift its LNG strategy in view of the latest developments notably on the European market.
Instead, he told reporters he had hoped the accord would lead to bilateral cooperation on liquefied natural gas.
Representatives from Gazprom in Moscow later confirmed the termination of the Algerian-Russian natural gas cooperation pact saying the two sides have, now, differing approaches on the matter.
Sunday, December 16, 2007
Anadarko Snake Drilling in the Rocky Mountains
Technological advances and Americans' hearty appetite for natural gas have given Anadarko Petroleum Corp. the opportunity to break new ground — literally and figuratively — in this remote, rugged region of the Rocky Mountains.
On a cliff several hundred feet above the White River, Texas-based Anadarko is drilling 17 wells from a single location — a dozen more than it's drilled from a single site in the past.
Rather than spread the wells across the landscape, they'll be concentrated in a relatively small area. The ultimate goal is to snake the drill bit thousands of feet into the earth, tapping natural-gas supplies beneath the river.
"The driving factor is being able to get under the river," said Jordan Hixson, who supervises Anadarko's production operations in northeastern Utah. "We can't get to it drilling conventional, vertical wells."
By using increasingly sophisticated — and more expensive — drilling methods and equipment, Anadarko and others are expanding their presence but reducing their "environmental footprint" throughout the Rockies and elsewhere. They're doing so primarily by consolidating wells to groups of 17, 22 and even larger combinations, then drilling in a variety of directions to reach reservoirs — some previously inaccessible.
In Utah, where Anadarko plans to go from 1,200 to 3,500 wells, the company is targeting 24-well combos next year. Its 17-well site occupies about 7 acres; a single-well pad is typically 2 to 2 1/2 acres.
Royal Dutch Shell PLC, Williams Cos. and others are expanding their use of the practice in Wyoming, Colorado, New Mexico and other states.
On a cliff several hundred feet above the White River, Texas-based Anadarko is drilling 17 wells from a single location — a dozen more than it's drilled from a single site in the past.
Rather than spread the wells across the landscape, they'll be concentrated in a relatively small area. The ultimate goal is to snake the drill bit thousands of feet into the earth, tapping natural-gas supplies beneath the river.
"The driving factor is being able to get under the river," said Jordan Hixson, who supervises Anadarko's production operations in northeastern Utah. "We can't get to it drilling conventional, vertical wells."
By using increasingly sophisticated — and more expensive — drilling methods and equipment, Anadarko and others are expanding their presence but reducing their "environmental footprint" throughout the Rockies and elsewhere. They're doing so primarily by consolidating wells to groups of 17, 22 and even larger combinations, then drilling in a variety of directions to reach reservoirs — some previously inaccessible.
In Utah, where Anadarko plans to go from 1,200 to 3,500 wells, the company is targeting 24-well combos next year. Its 17-well site occupies about 7 acres; a single-well pad is typically 2 to 2 1/2 acres.
Royal Dutch Shell PLC, Williams Cos. and others are expanding their use of the practice in Wyoming, Colorado, New Mexico and other states.
Saturday, December 15, 2007
Canadian Natural Gas Down - Oil Drill Up for 2008
Natural gas producers and drillers, whose field activity plummeted this year probably won‘t be seeing much relief in 2008, while action in the oilsands is expected to intensify thanks to record-high crude oil prices.
The bottoming out of North American natural gas markets coupled with the soaring loonie made for an “unpleasant and difficult‘‘ year, said Don Herring, president of the Canadian Association of Oilwell Drilling Contractors, adding that in 2008 “the story continues to worsen.‘‘
Herring‘s group predicts a huge in drilling in 2008. The industry drilled 6,000 fewer wells this year than in did in 2006 and next year it expects to see that figure by about another 2,560 _ a 38 per cent within two years.
The Petroleum Services Association of Canada also released dismal predictions for 2008. That group forecasts drilling to go down by 17 per cent between 2007 and 2008.
Natural gas prices hit record highs in the fall of 2005, a particularly bad hurricane season for the U.S. Gulf Coast, which hosts a number of major gaswells and gathering pipelines. But since then, North America has experienced two warm winters and one tame hurricane season, leading to a big supply surplus.
In addition, the expansion of liquefied natural gas projects has d a global market for LNG, which would freeze and liquefy gas produced in Russia, the Middle East and South America and ship it by tanker to North American markets, where it would be regassified and used to boost supplies to consumers, businesses and power plants.
The average price of natural gas in North America was about $6.50 per thousand cubic feet this year.
“A large number of potential wells are uneconomic at that price. Really to make gas economic again in Canada, we need prices north of $8.‘‘ said PSAC president Roger Soucy.
“There‘s a lot of gas in North America right now as a result of some warm winters and we don‘t expect that we‘re going to come out of this heating season next March with a whole lot changed.‘‘
It has been a different story in Alberta‘s oilsands where businesses there have been reaping the benefits of record-high crude oil prices. Oil started off the year at around the US$60 a barrel mark and came close to US$100 before losing ground on concerns about the impact a U.S. recession would have on global oil demand.
A number of Canadian energy giants _ like EnCana Corp. (TSX:ECA), Petro-Canada (TSX:PCA) and Husky Energy Inc.(TSX:HSE) _ have outlined plans to expand their oilsands operations in their 2008 capital spending plans.
International producers have also been looking to increase their stake in the vast Athabasca oilsands in northern Alberta, which are believed to contain 175 billion barrels of oil _ second only to Saudi Arabia‘s reserves.
At the beginning of the year, EnCana inked a $15-billion deal with Houston-based giant ConocoPhillips. Under that deal, EnCana would gain 50 per cent of two ConocoPhillips (NYSE:COP) refineries while the U.S. company would have a half stake in EnCana‘s Foster Creek and Christina Lake oilsands projects.
Earlier this month Husky Energy reached a similar deal with Britain‘s BP Plc worth $5.5 billion. Each company gets a 50 per cent stake in Husky‘s Sunrise oilsands project and BP‘s Toledo refinery.
State-owned players like Norway‘s Statoil, China‘s Sinopec and France‘s Total have bought into the oilsands and Japanese, Korean and Italian players are thought to be next.
The bottoming out of North American natural gas markets coupled with the soaring loonie made for an “unpleasant and difficult‘‘ year, said Don Herring, president of the Canadian Association of Oilwell Drilling Contractors, adding that in 2008 “the story continues to worsen.‘‘
Herring‘s group predicts a huge in drilling in 2008. The industry drilled 6,000 fewer wells this year than in did in 2006 and next year it expects to see that figure by about another 2,560 _ a 38 per cent within two years.
The Petroleum Services Association of Canada also released dismal predictions for 2008. That group forecasts drilling to go down by 17 per cent between 2007 and 2008.
Natural gas prices hit record highs in the fall of 2005, a particularly bad hurricane season for the U.S. Gulf Coast, which hosts a number of major gaswells and gathering pipelines. But since then, North America has experienced two warm winters and one tame hurricane season, leading to a big supply surplus.
In addition, the expansion of liquefied natural gas projects has d a global market for LNG, which would freeze and liquefy gas produced in Russia, the Middle East and South America and ship it by tanker to North American markets, where it would be regassified and used to boost supplies to consumers, businesses and power plants.
The average price of natural gas in North America was about $6.50 per thousand cubic feet this year.
“A large number of potential wells are uneconomic at that price. Really to make gas economic again in Canada, we need prices north of $8.‘‘ said PSAC president Roger Soucy.
“There‘s a lot of gas in North America right now as a result of some warm winters and we don‘t expect that we‘re going to come out of this heating season next March with a whole lot changed.‘‘
It has been a different story in Alberta‘s oilsands where businesses there have been reaping the benefits of record-high crude oil prices. Oil started off the year at around the US$60 a barrel mark and came close to US$100 before losing ground on concerns about the impact a U.S. recession would have on global oil demand.
A number of Canadian energy giants _ like EnCana Corp. (TSX:ECA), Petro-Canada (TSX:PCA) and Husky Energy Inc.(TSX:HSE) _ have outlined plans to expand their oilsands operations in their 2008 capital spending plans.
International producers have also been looking to increase their stake in the vast Athabasca oilsands in northern Alberta, which are believed to contain 175 billion barrels of oil _ second only to Saudi Arabia‘s reserves.
At the beginning of the year, EnCana inked a $15-billion deal with Houston-based giant ConocoPhillips. Under that deal, EnCana would gain 50 per cent of two ConocoPhillips (NYSE:COP) refineries while the U.S. company would have a half stake in EnCana‘s Foster Creek and Christina Lake oilsands projects.
Earlier this month Husky Energy reached a similar deal with Britain‘s BP Plc worth $5.5 billion. Each company gets a 50 per cent stake in Husky‘s Sunrise oilsands project and BP‘s Toledo refinery.
State-owned players like Norway‘s Statoil, China‘s Sinopec and France‘s Total have bought into the oilsands and Japanese, Korean and Italian players are thought to be next.
Friday, December 14, 2007
Occidental Wins Libya Gas Exploration Contract
Libya Wednesday awarded two gas exploration contracts to U.S. fuel giant Occidental Petroleum (OXY) and Germany's RWE (RWEOY), according to Tripoli's National Oil Corporation.
Occidental was granted four exploration blocks in the Sirte basin around 600 kilometres east of the capital, comprising a total area of around 5,000 square kilometres.
RWE was awarded an exploration zone of four blocks and spanning 10,289 square kilometres in the Berka region near Benghazi, around 1,000 kilometres east of Tripoli.
Sunday, Libya awarded four potentially lucrative gas contracts to Shell (RDSB) , Gazprom (GAZP.RS), Sonatrach and Poland's PGNIG -- the first ever given to foreign firms.
A total of 35 companies had been pre-selected to bid for the dozen contracts to explore 41 gas blocks in the Mediterranean. The blocks cover a total of 72, 500 square kilometres, an area about the size of Scotland.
It was the first time Libya invited tenders for natural gas exploration. Six further contracts have yet to be awarded.
OPEC member Libya is the African continent's second-largest oil producer at 1.7 million barrels per day. It also has natural gas reserves estimated at 1,314 billion cubic metres.
Occidental was granted four exploration blocks in the Sirte basin around 600 kilometres east of the capital, comprising a total area of around 5,000 square kilometres.
RWE was awarded an exploration zone of four blocks and spanning 10,289 square kilometres in the Berka region near Benghazi, around 1,000 kilometres east of Tripoli.
Sunday, Libya awarded four potentially lucrative gas contracts to Shell (RDSB) , Gazprom (GAZP.RS), Sonatrach and Poland's PGNIG -- the first ever given to foreign firms.
A total of 35 companies had been pre-selected to bid for the dozen contracts to explore 41 gas blocks in the Mediterranean. The blocks cover a total of 72, 500 square kilometres, an area about the size of Scotland.
It was the first time Libya invited tenders for natural gas exploration. Six further contracts have yet to be awarded.
OPEC member Libya is the African continent's second-largest oil producer at 1.7 million barrels per day. It also has natural gas reserves estimated at 1,314 billion cubic metres.
Thursday, December 13, 2007
Natural Gas Pipeline for British Columbia
Spectra Energy (NYSE:SE) Wednesday proposed the construction of an 85-kilometer natural gas pipeline to connect an exploration area in the northeast area of British Columbia with its existing transportation infrastructure.
The cost of the construction was estimated at $100 million Canadian, with the in-service date scheduled for the third quarter of 2009.
Shares of Spectra, a Calgary-based natural gas company, rose 2.2% to $24.89.
The cost of the construction was estimated at $100 million Canadian, with the in-service date scheduled for the third quarter of 2009.
Shares of Spectra, a Calgary-based natural gas company, rose 2.2% to $24.89.
Wednesday, December 12, 2007
Exxon Building LNG Plant 20 Miles Offshore NY
Exxon Mobil said Tuesday that it would like to build a $1 billion floating terminal for liquefied natural gas about 20 miles off the coast of New Jersey, a move meant to deflect safety and environmental concerns about proximity to populated areas.
The company plans to anchor a boatlike structure in the Atlantic Ocean to process natural gas imported by cargo ships from faraway suppliers in the Middle East, Europe and Africa.
The terminal, if approved, would connect through an underwater pipeline to an existing network that feeds New York and New Jersey, two of the top consumer markets in North America.
Exxon’s project is the latest of several dozen gas terminals that have been proposed in recent years in the United States. Energy specialists say more natural gas supplies will be needed to meet the growth in consumption and to make up for an expected drop in imports from Canada.
In many cases, energy companies have faced stiff opposition in finding sites for large new terminals. This has become one of the thorniest energy issues, especially since the attacks of Sept. 11, 2001, raised security concerns about cargo ships carrying liquefied gas near big cities.
Still, companies are slowly moving forward with their plans. Since 2002, federal and state authorities have approved 18 new liquefied gas terminals around the country, including 4 offshore, though most analysts do not expect all of them to be built.
While most of the projects are planned along the Gulf Coast, the northeastern corner of the country is attracting attention because of its reliance on natural gas and its large populations. Two terminals to be built off Massachusetts gained approval last year. For Exxon, going so far offshore is an effort to duck the vociferous opposition that has dogged projects on both coasts. Its project, called BlueOcean Energy, would be able to supply 1.2 billion cubic feet of natural gas a day, about 2 percent of the nation’s gas consumption — and enough to meet the needs of five million residential customers.
Exxon’s project is the third offshore terminal proposed for the greater New York region in recent years.
One proposal, to build a gas terminal in the middle of Long Island Sound, has aroused concern since its announcement in 2004 because of the impact it might have on fishing and boating; it is strongly opposed by shore communities and politicians.
That opposition could intensify in coming months as the project, which is known as Broadwater and is a joint venture by Royal Dutch Shell and TransCanada, is expected to receive notice about federal and state permits.
Another company, the Atlantic Sea Island Group, plans to build a terminal for liquefied natural gas on an artificial island about 14 miles south of Long Island, a project called Safe Harbor Energy.
The company plans to anchor a boatlike structure in the Atlantic Ocean to process natural gas imported by cargo ships from faraway suppliers in the Middle East, Europe and Africa.
The terminal, if approved, would connect through an underwater pipeline to an existing network that feeds New York and New Jersey, two of the top consumer markets in North America.
Exxon’s project is the latest of several dozen gas terminals that have been proposed in recent years in the United States. Energy specialists say more natural gas supplies will be needed to meet the growth in consumption and to make up for an expected drop in imports from Canada.
In many cases, energy companies have faced stiff opposition in finding sites for large new terminals. This has become one of the thorniest energy issues, especially since the attacks of Sept. 11, 2001, raised security concerns about cargo ships carrying liquefied gas near big cities.
Still, companies are slowly moving forward with their plans. Since 2002, federal and state authorities have approved 18 new liquefied gas terminals around the country, including 4 offshore, though most analysts do not expect all of them to be built.
While most of the projects are planned along the Gulf Coast, the northeastern corner of the country is attracting attention because of its reliance on natural gas and its large populations. Two terminals to be built off Massachusetts gained approval last year. For Exxon, going so far offshore is an effort to duck the vociferous opposition that has dogged projects on both coasts. Its project, called BlueOcean Energy, would be able to supply 1.2 billion cubic feet of natural gas a day, about 2 percent of the nation’s gas consumption — and enough to meet the needs of five million residential customers.
Exxon’s project is the third offshore terminal proposed for the greater New York region in recent years.
One proposal, to build a gas terminal in the middle of Long Island Sound, has aroused concern since its announcement in 2004 because of the impact it might have on fishing and boating; it is strongly opposed by shore communities and politicians.
That opposition could intensify in coming months as the project, which is known as Broadwater and is a joint venture by Royal Dutch Shell and TransCanada, is expected to receive notice about federal and state permits.
Another company, the Atlantic Sea Island Group, plans to build a terminal for liquefied natural gas on an artificial island about 14 miles south of Long Island, a project called Safe Harbor Energy.
Tuesday, December 11, 2007
Angola Natural Gas Project is a Chevron
A natural gas project backed by Chevron Corp., BP plc and Total SA has been approved for construction by the government of the African nation of Angola.
The joint venture, named Angola LNG Ltd., in which Chevron (NYSE: CVX) has a 36.4 percent stake, will collect natural gas from offshore fields in the Atlantic Ocean and process it at a new plant near Soyo, a town on Angola's northern coast, just south of the Congo River.
Most of Angola's oil and gas deposits are offshore from Cabinda, an enclave north of the Congo River which is owned by Angola, though it is divided from the main section of the country by part of the Democratic Republic of the Congo, formerly known as Zaire.
The joint venture, named Angola LNG Ltd., in which Chevron (NYSE: CVX) has a 36.4 percent stake, will collect natural gas from offshore fields in the Atlantic Ocean and process it at a new plant near Soyo, a town on Angola's northern coast, just south of the Congo River.
Most of Angola's oil and gas deposits are offshore from Cabinda, an enclave north of the Congo River which is owned by Angola, though it is divided from the main section of the country by part of the Democratic Republic of the Congo, formerly known as Zaire.
Monday, December 10, 2007
Libya Awards Natural Gas Contracts for 1st Time
Libya on Sunday awarded four potentially lucrative gas exploration contracts to fuel giants Shell, Gazprom, Sonatrach and Polski, the first ever given to foreign firms as relations warm between Tripoli and the West.
The biggest award went to Algerian firm Sonatrach in association with Oil India and Indian Oil, which was given four blocks covering 6,934 square kilometres (2,677 square miles).
Russian giant Gazprom was awarded three exploration blocs with a total area of 3,936 square kilometres in the southern Ghadames basin.
Gazprom beat off competition from Gaz de France, Inpex of Japan, Russian rival Lukoil, Britain's BG and Polski, agreeing to cede 90 percent of its eventual production to Libya's state-owned National Oil Corporation (NOC).
Anglo-Dutch company Shell was handed a two-block contract to explore a 1,790 square kilometre area in the northern Sirte basin and Polish firm Polski was also awarded a two-block area in the southern Murzak basin.
Shell was awarded its exploration rights following a bid of 93 million dollars and 85 percent of its eventual production.
Sonatrach outbid Gaz de France, BG, Polski and Germany's RWE and proposed 87 percent of its production go to the NOC.
A total of 35 companies had been pre-selected to bid for the dozen contracts awarded Sunday to explore 41 gas blocks in the Mediterranean, the Sirte basin in the north-central area of the country, Cyrenaica further east and Murzek and Ghadames in the south.
The blocks cover a total of 72,500 square kilometres (almost 28,000 square miles), an area the size of Scotland.
It was the first time Libya invited tenders for natural gas exploration.
The biggest award went to Algerian firm Sonatrach in association with Oil India and Indian Oil, which was given four blocks covering 6,934 square kilometres (2,677 square miles).
Russian giant Gazprom was awarded three exploration blocs with a total area of 3,936 square kilometres in the southern Ghadames basin.
Gazprom beat off competition from Gaz de France, Inpex of Japan, Russian rival Lukoil, Britain's BG and Polski, agreeing to cede 90 percent of its eventual production to Libya's state-owned National Oil Corporation (NOC).
Anglo-Dutch company Shell was handed a two-block contract to explore a 1,790 square kilometre area in the northern Sirte basin and Polish firm Polski was also awarded a two-block area in the southern Murzak basin.
Shell was awarded its exploration rights following a bid of 93 million dollars and 85 percent of its eventual production.
Sonatrach outbid Gaz de France, BG, Polski and Germany's RWE and proposed 87 percent of its production go to the NOC.
A total of 35 companies had been pre-selected to bid for the dozen contracts awarded Sunday to explore 41 gas blocks in the Mediterranean, the Sirte basin in the north-central area of the country, Cyrenaica further east and Murzek and Ghadames in the south.
The blocks cover a total of 72,500 square kilometres (almost 28,000 square miles), an area the size of Scotland.
It was the first time Libya invited tenders for natural gas exploration.
Sunday, December 9, 2007
Panhandle Natural Gas Production Up
PANHANDLE OIL AND GAS INC. reported total proved reserves at September 30, 2007,
calculated by the Company's petroleum engineering consulting firm, totaled
41.9 bcfe an increase of 22% over year end September 30, 2006 proved reserves
of 34.3 bcfe. Of the 41.9 bcfe of total proved reserves only 15% or 6.4 bcfe
are proved undeveloped reserves.
Production for fiscal 2007 increased 19% to 5,791,407 mcfe as compared to
4,881,976 mcfe for fiscal 2006; however, the Company's average sales price per
mcfe declined $.91 to $6.47 in fiscal 2007. Further, production for the
fourth quarter of 2007 increased 25% to 1,719,986 mcfe as compared to
1,376,926 mcfe for the fourth quarter of 2006. The average sales price in the
2007 quarter decreased $.20 per mcfe to $6.24 as compared to the 2006 quarter.
Fiscal year ended September 30, 2007 net income was $6,343,464, or $.75
per share, as compared to net income for fiscal year 2006 of $10,574,219, or
$1.25 per share. Total revenues for fiscal 2007 were $39,128,911 as compared
to $37,485,680 for fiscal 2006. Cash flow from operations increased 20% for
fiscal 2007 to $28,106,500 as compared to $23,470,145 for fiscal 2006.
Additions to properties and equipment for drilling and equipping wells and
purchasing leasehold totaled $28,112,522 in fiscal 2007 as compared to
$22,624,040 for 2006.
calculated by the Company's petroleum engineering consulting firm, totaled
41.9 bcfe an increase of 22% over year end September 30, 2006 proved reserves
of 34.3 bcfe. Of the 41.9 bcfe of total proved reserves only 15% or 6.4 bcfe
are proved undeveloped reserves.
Production for fiscal 2007 increased 19% to 5,791,407 mcfe as compared to
4,881,976 mcfe for fiscal 2006; however, the Company's average sales price per
mcfe declined $.91 to $6.47 in fiscal 2007. Further, production for the
fourth quarter of 2007 increased 25% to 1,719,986 mcfe as compared to
1,376,926 mcfe for the fourth quarter of 2006. The average sales price in the
2007 quarter decreased $.20 per mcfe to $6.24 as compared to the 2006 quarter.
Fiscal year ended September 30, 2007 net income was $6,343,464, or $.75
per share, as compared to net income for fiscal year 2006 of $10,574,219, or
$1.25 per share. Total revenues for fiscal 2007 were $39,128,911 as compared
to $37,485,680 for fiscal 2006. Cash flow from operations increased 20% for
fiscal 2007 to $28,106,500 as compared to $23,470,145 for fiscal 2006.
Additions to properties and equipment for drilling and equipping wells and
purchasing leasehold totaled $28,112,522 in fiscal 2007 as compared to
$22,624,040 for 2006.
Saturday, December 8, 2007
PetroBras Strikes Natural Gas 34Miles Offshore
Brazil's state-owned oil and gas giant Petrobras on Friday claimed the discovery of an offshore natural gas reserve in the southeastern state of Espirito Santo.
The company said a well in the reserve, 3,378 meters deep in the Camarupim field and 37 km away from the coast, was drilled in the BM-ES-5 area, in which Petrobras holds a 65-percent stake, while the U.S. company El Paso owns the remaining 35 percent.
The company also announced the presence of good quality oil at a depth of 2,461 meters in the same field.
The finding confirms that the Espirito Santo basin has more natural gas than initially estimated, possibly making it one of the top gas providers in the country by 2009, abreast with the Campos Basin in the state of Rio de Janeiro, according to the company.
The company said a well in the reserve, 3,378 meters deep in the Camarupim field and 37 km away from the coast, was drilled in the BM-ES-5 area, in which Petrobras holds a 65-percent stake, while the U.S. company El Paso owns the remaining 35 percent.
The company also announced the presence of good quality oil at a depth of 2,461 meters in the same field.
The finding confirms that the Espirito Santo basin has more natural gas than initially estimated, possibly making it one of the top gas providers in the country by 2009, abreast with the Campos Basin in the state of Rio de Janeiro, according to the company.
Friday, December 7, 2007
Myanmar Natural Gas Tender Won by China
China won the rights to natural gas from the biggest field in Myanmar, beating India in the race for resources among the two-fastest growing major economies.
Daewoo International, the operator of the field, picked a Chinese company as the preferred bidder to extract the gas, Daewoo International said in a regulatory filing, without naming the possible buyer. State-owned Indian companies own 30 percent of the field, which holds as much as 7.7 trillion cubic feet, or 218 billion cubic meters, of gas.
Gas commands a premium for fuel-hungry Asian nations as crude oil prices hover near $100 a barrel. India and China are competing for oil and gas to supply the two most populous nations in the world.
Daewoo International is the operator of the A-1 and A-3 offshore blocks, in which it has a 60 percent stake. Korea Gas owns 10 percent of the areas, GAIL India holds 10 percent and Oil & Natural Gas owns 20 percent.
"Gas from the field has to be sold and if Daewoo has chosen China, in principle, I see nothing wrong with it," the chairman of Oil & Natural Gas, R.S. Sharma, said. "GAIL was dealing with the bit relating to getting the gas to India."
Daewoo International, the operator of the field, picked a Chinese company as the preferred bidder to extract the gas, Daewoo International said in a regulatory filing, without naming the possible buyer. State-owned Indian companies own 30 percent of the field, which holds as much as 7.7 trillion cubic feet, or 218 billion cubic meters, of gas.
Gas commands a premium for fuel-hungry Asian nations as crude oil prices hover near $100 a barrel. India and China are competing for oil and gas to supply the two most populous nations in the world.
Daewoo International is the operator of the A-1 and A-3 offshore blocks, in which it has a 60 percent stake. Korea Gas owns 10 percent of the areas, GAIL India holds 10 percent and Oil & Natural Gas owns 20 percent.
"Gas from the field has to be sold and if Daewoo has chosen China, in principle, I see nothing wrong with it," the chairman of Oil & Natural Gas, R.S. Sharma, said. "GAIL was dealing with the bit relating to getting the gas to India."
Thursday, December 6, 2007
Ukraine Gets Gazprom $180/1000 cubic meters
Reacting to news of the stiff price hike on natural gas inked by Ukraine’s outgoing government, Yulia Tymoshenko, the opposition leader who is poised to return as Ukraine’s prime minister, lambasted the deal and vowed to eliminate middleman companies in negotiating energy deals.
“This is a result of an absolutely brainless policy of setting up RosUkrEnergo as a broker,” the Associated Press reported Tymoshenko as saying on Dec. 4, the day Russian energy giant Gazprom announced stiff price hikes for Ukraine.
“There is no logic here. This is corruption,” she was quoted as saying. “Undoubtedly, if our team comes to power, we will do all we can so that Ukraine and Russia have the opportunity to work without any go-betweens,” she added.
Late on Dec. 4, Gazprom announced Ukraine would pay nearly $180 per 1,000 cubic meters of Russian natural gas beginning next year, a 40 percent increase over current prices.
Nearly all the gas Ukraine uses is imported via Russia from the energy-rich Central Asian nation of Turkmenistan. Some of the gas is also of Uzbek and Kazakh origin. The gas is imported through a Swiss-based trading company, RosUkrEnergo, half of which is owned by Gazprom and half by two Ukrainian businessmen.
RosUkrEnergo spokesman Andrei Knutov said no official documents have been signed, but that was expected to happen in the coming days.
Ukraine’s energy minister said a final deal could be inked on Dec. 5.
The deal comes one week after Gazprom announced it would pay up to 30 percent more beginning next year for natural gas from Turkmenistan, which Gazprom resells to Ukraine.
“This is a result of an absolutely brainless policy of setting up RosUkrEnergo as a broker,” the Associated Press reported Tymoshenko as saying on Dec. 4, the day Russian energy giant Gazprom announced stiff price hikes for Ukraine.
“There is no logic here. This is corruption,” she was quoted as saying. “Undoubtedly, if our team comes to power, we will do all we can so that Ukraine and Russia have the opportunity to work without any go-betweens,” she added.
Late on Dec. 4, Gazprom announced Ukraine would pay nearly $180 per 1,000 cubic meters of Russian natural gas beginning next year, a 40 percent increase over current prices.
Nearly all the gas Ukraine uses is imported via Russia from the energy-rich Central Asian nation of Turkmenistan. Some of the gas is also of Uzbek and Kazakh origin. The gas is imported through a Swiss-based trading company, RosUkrEnergo, half of which is owned by Gazprom and half by two Ukrainian businessmen.
RosUkrEnergo spokesman Andrei Knutov said no official documents have been signed, but that was expected to happen in the coming days.
Ukraine’s energy minister said a final deal could be inked on Dec. 5.
The deal comes one week after Gazprom announced it would pay up to 30 percent more beginning next year for natural gas from Turkmenistan, which Gazprom resells to Ukraine.
Day Traders Failed to Manipulate Natural Gas Price
Three former El Paso Corp. traders' efforts to manipulate the price of natural gas by reporting false data were driven by greed, prosecutors told jurors Wednesday.
But defense attorneys for James Brooks, Wesley C. Walton and James Patrick Phillips told jurors the ex-traders never submitted false data and were victims of unclear policies on how to report pricing information.
Each defendant is on trial for 49 counts of conspiracy, false reporting and wire fraud related to accusations of reporting bogus trade data used to calculate natural gas index prices. If convicted, each faces up to five years in prison and a fine up to $500,000 for each count.
Natural gas price indexes are used to price billions of dollars in transactions involving natural gas and electricity in physical and financial markets each year. El Paso owns the largest network of natural gas pipelines in the country.
Prosecutor John Lewis told jurors during opening statements that the trio from 2000 to 2002 transmitted 81 reports containing false data to Inside FERC Natural Gas Report and Natural Gas Intelligence, two industry journals.
The journals conduct pricing surveys of natural gas bought and sold in the country by polling traders. The three ex-traders submitted false data to the journals in order to drive up or down the daily price of natural gas, Lewis said.
They reported the bogus trade data in order to earn more profits for their company and as a result get paid bigger work bonuses, he said.
"You can see the potential for abuse and abused this system was," Lewis said.
Brooks, who was El Paso's former head of natural gas trading, was the person most responsible for fraud at the company, Lewis said.
"He ordered (employees) to do it even when employees objected," he said. "Brooks ordered fraud to take place. Walton guided it. Phillips carried it out."
Wendell Odom, Brooks' attorney, told jurors that while his client was a "hard-driving" trader, he didn't submit false data.
"All of the (false) reporting we are accused of doing is going to be within the range of what people actually purchased and sold natural gas for," he said.
Odom denied Brooks or the others earned big bonuses for their work.
"He's a good man," Odom said.
Lewis told jurors that prosecutors would play recordings of business calls in which all three defendants talked and bragged about manipulating prices.
David Gerger, Walton's attorney, said prosecutors are taking the calls out of context.
"They are cursing like a sailor, boasting, bragging," he said. "That horrible language that traders talk is not a crime. What he's accused of, the evidence will show you he didn't do."
David Adler, Phillips' attorney, told jurors his client is a hardworking family man who never got instructions from his company or the trade journals on how to report the natural gas data.
"The information he sent was from actual trades. It's not fake information," Adler said. "Others may have sent fake numbers."
But defense attorneys for James Brooks, Wesley C. Walton and James Patrick Phillips told jurors the ex-traders never submitted false data and were victims of unclear policies on how to report pricing information.
Each defendant is on trial for 49 counts of conspiracy, false reporting and wire fraud related to accusations of reporting bogus trade data used to calculate natural gas index prices. If convicted, each faces up to five years in prison and a fine up to $500,000 for each count.
Natural gas price indexes are used to price billions of dollars in transactions involving natural gas and electricity in physical and financial markets each year. El Paso owns the largest network of natural gas pipelines in the country.
Prosecutor John Lewis told jurors during opening statements that the trio from 2000 to 2002 transmitted 81 reports containing false data to Inside FERC Natural Gas Report and Natural Gas Intelligence, two industry journals.
The journals conduct pricing surveys of natural gas bought and sold in the country by polling traders. The three ex-traders submitted false data to the journals in order to drive up or down the daily price of natural gas, Lewis said.
They reported the bogus trade data in order to earn more profits for their company and as a result get paid bigger work bonuses, he said.
"You can see the potential for abuse and abused this system was," Lewis said.
Brooks, who was El Paso's former head of natural gas trading, was the person most responsible for fraud at the company, Lewis said.
"He ordered (employees) to do it even when employees objected," he said. "Brooks ordered fraud to take place. Walton guided it. Phillips carried it out."
Wendell Odom, Brooks' attorney, told jurors that while his client was a "hard-driving" trader, he didn't submit false data.
"All of the (false) reporting we are accused of doing is going to be within the range of what people actually purchased and sold natural gas for," he said.
Odom denied Brooks or the others earned big bonuses for their work.
"He's a good man," Odom said.
Lewis told jurors that prosecutors would play recordings of business calls in which all three defendants talked and bragged about manipulating prices.
David Gerger, Walton's attorney, said prosecutors are taking the calls out of context.
"They are cursing like a sailor, boasting, bragging," he said. "That horrible language that traders talk is not a crime. What he's accused of, the evidence will show you he didn't do."
David Adler, Phillips' attorney, told jurors his client is a hardworking family man who never got instructions from his company or the trade journals on how to report the natural gas data.
"The information he sent was from actual trades. It's not fake information," Adler said. "Others may have sent fake numbers."
Wednesday, December 5, 2007
Natural Gas Bidding Tricky in Alaska
Alaska's unfolding political-corruption scandal deterred one energy company from submitting a natural gas pipeline proposal to the state, while uncertain economics precluded the proposal of another.
MidAmerican Energy Holdings Co. (MDPWN.OB: Quote, Profile , Research) and BG Group Plc (BG.L: Quote, Profile , Research), companies that had been expected to bid for a state license to build a long-awaited natural gas pipeline project under the new Alaska Gasline Inducement Act, said they declined to participate because of an unfolding bribery scandal and shaky economics, respectively.
"For a project of this magnitude to proceed, integrity must be the foundation upon which all project elements are based," MidAmerican Chairman David Sokol said a letter sent Friday to Alaska Gov. Sarah Palin.
"As you are painfully aware, the ongoing corruption investigations coupled with previous indictments, guilty pleas and convictions draw into question virtually every major Alaskan project participant and governmental levels from State to Federal," he said.
Two executives from Alaska's largest oil-services company have pleaded guilty to a variety of bribery and corruption charges resulting from the wide-ranging federal investigation. Three former state legislators have been convicted in trials held so far, and a fourth trial is pending.
BG's Managing Director Martin Houston said in a Nov. 29 letter to Palin that the company still hopes to participate in whatever gas project emerges.
MidAmerican Energy Holdings Co. (MDPWN.OB: Quote, Profile , Research) and BG Group Plc (BG.L: Quote, Profile , Research), companies that had been expected to bid for a state license to build a long-awaited natural gas pipeline project under the new Alaska Gasline Inducement Act, said they declined to participate because of an unfolding bribery scandal and shaky economics, respectively.
"For a project of this magnitude to proceed, integrity must be the foundation upon which all project elements are based," MidAmerican Chairman David Sokol said a letter sent Friday to Alaska Gov. Sarah Palin.
"As you are painfully aware, the ongoing corruption investigations coupled with previous indictments, guilty pleas and convictions draw into question virtually every major Alaskan project participant and governmental levels from State to Federal," he said.
Two executives from Alaska's largest oil-services company have pleaded guilty to a variety of bribery and corruption charges resulting from the wide-ranging federal investigation. Three former state legislators have been convicted in trials held so far, and a fourth trial is pending.
BG's Managing Director Martin Houston said in a Nov. 29 letter to Palin that the company still hopes to participate in whatever gas project emerges.
Tuesday, December 4, 2007
El Paso Corp Planning 2 Billion/Day Natural Gas Line
Another major natural gas pipeline from the Rocky Mountains to other markets was announced Monday, when El Paso Corp. said it wants to build a pipeline from southwestern Wyoming to Oregon.
El Paso is based in Houston.
It's one of several pipeline projects announced recently to expand the Industry's capacity to ship natural gas out of the Rocky Mountains.
El Paso said it's filed a right-of-way application with the Bureau of Land Management for the "Ruby Pipeline" project -- a 680-mile, 42-inch pipeline to carry natural gas from the Opal Hub in Wyoming to another hub in Malin, Ore., near California's northern border.
An El Paso spokesman said the company wasn't releasing a cost estimate on the project.
The pipeline will have an initial capacity of 1.2 billion cubic feet per day -- similar to the $4.4 billion Rockies Express pipeline that will carry natural gas from Colorado's Western Slope 1,678 miles to eastern Ohio. El Paso said the Ruby pipeline will be expandable to 2 billion cubic feet per day.
El Paso is based in Houston.
It's one of several pipeline projects announced recently to expand the Industry's capacity to ship natural gas out of the Rocky Mountains.
El Paso said it's filed a right-of-way application with the Bureau of Land Management for the "Ruby Pipeline" project -- a 680-mile, 42-inch pipeline to carry natural gas from the Opal Hub in Wyoming to another hub in Malin, Ore., near California's northern border.
An El Paso spokesman said the company wasn't releasing a cost estimate on the project.
The pipeline will have an initial capacity of 1.2 billion cubic feet per day -- similar to the $4.4 billion Rockies Express pipeline that will carry natural gas from Colorado's Western Slope 1,678 miles to eastern Ohio. El Paso said the Ruby pipeline will be expandable to 2 billion cubic feet per day.
Monday, December 3, 2007
China Petrochemical Wants Alaska Natural Gas
China Petrochemical Corp is among companies including TransCanada Corp and ConocoPhillips competing to build a pipeline that would allow the first commercial production of natural gas from Alaska's North Slope.
Five companies have applied to build the pipeline, Alaska Governor Sarah Palin said in a statement on Friday, without providing details of their plans.
ConocoPhillips said earlier it submitted a proposal for a US$30 billion conduit that would ship four billion cubic feet of gas a day to markets in the US and Canada.
Producers are reviving plans to tap gas deposits discovered in Alaska decades ago as gains in demand boosted prices for the heating and power-plant fuel and fields that are cheaper to develop become scarce.
North Slope gas reserves, estimated at 35 trillion cubic feet by the state, are currently inaccessible as there's no way to get the fuel to consumers.
"This progress demonstrates to the world that Alaska is well on our way to bringing this long sought-after necessary infrastructure to fruition," Palin said late yesterday at a briefing in Anchorage, which was broadcast over the Internet.
Five companies have applied to build the pipeline, Alaska Governor Sarah Palin said in a statement on Friday, without providing details of their plans.
ConocoPhillips said earlier it submitted a proposal for a US$30 billion conduit that would ship four billion cubic feet of gas a day to markets in the US and Canada.
Producers are reviving plans to tap gas deposits discovered in Alaska decades ago as gains in demand boosted prices for the heating and power-plant fuel and fields that are cheaper to develop become scarce.
North Slope gas reserves, estimated at 35 trillion cubic feet by the state, are currently inaccessible as there's no way to get the fuel to consumers.
"This progress demonstrates to the world that Alaska is well on our way to bringing this long sought-after necessary infrastructure to fruition," Palin said late yesterday at a briefing in Anchorage, which was broadcast over the Internet.
Sunday, December 2, 2007
ConocoPhillips Wants Alaska Natural Gas Pipeline
ConocoPhillips wants to build potentially the world's largest, most expensive energy facility — a multibillion dollar gas pipeline running from Alaska's North Slope to Midwestern states.
The project, with a price tag of up to $42 billion, would be worth it, if it can help supply North American homes and businesses with heating fuel for years to come.
ConocoPhillips, Alaska's leading North Slope oil producer, said Friday it's "prepared to make significant investments, without state matching funds, to advance this project."
It's the first proposal in the state-sponsored competition for a pipeline to tap the rich fields where the industry has identified about 36 trillion cubic feet of proved reserves that could be shipped within the next 10 to 12 years.
The project, with a price tag of up to $42 billion, would be worth it, if it can help supply North American homes and businesses with heating fuel for years to come.
ConocoPhillips, Alaska's leading North Slope oil producer, said Friday it's "prepared to make significant investments, without state matching funds, to advance this project."
It's the first proposal in the state-sponsored competition for a pipeline to tap the rich fields where the industry has identified about 36 trillion cubic feet of proved reserves that could be shipped within the next 10 to 12 years.
Saturday, December 1, 2007
Alaska Developing Natural Gas in North Slope
Five companies, partnerships and entities have submitted proposals to build a massive pipeline from Alaska's North Slope to bring the region's vast but long-languishing natural gas reserves to markets thousands of miles away, state officials announced late on Friday.
The proposals, submitted under the Alaska Gasline Inducement Act passed by the legislature earlier this year, will vie against each other for state support. Friday was the deadline for applications to be submitted.
"This is such an exciting day for Alaska and really an exciting day for America," Gov. Sarah Palin, who organized the competitive-bidding strategy, said at a news conference. "Today's progress under AGIA demonstrates to the world that Alaska is well on our way to bringing this long sought-after infrastructure, a natural gas pipeline, to fruition."
The proposals, submitted under the Alaska Gasline Inducement Act passed by the legislature earlier this year, will vie against each other for state support. Friday was the deadline for applications to be submitted.
"This is such an exciting day for Alaska and really an exciting day for America," Gov. Sarah Palin, who organized the competitive-bidding strategy, said at a news conference. "Today's progress under AGIA demonstrates to the world that Alaska is well on our way to bringing this long sought-after infrastructure, a natural gas pipeline, to fruition."
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