MOSCOW: Russia has reached agreement with South Korea to supply 10 billion cubic metres (BCM) of natural gas a year. The deal will help Russia diversify gas exports away from Europe, which seeks to reduce its dependence on Russian energy.
Under the preliminary agreement, signed on Monday on the sidelines of Korean President Lee Myung-bak’s visit to Moscow, a pipeline to South Korea will be laid via North Korea from gas fields on Sakhalin Island in Russia’s Far East. The pipeline will initially carry 10 BCM of gas a year, or about 20 per cent of South Korea’s annual consumption. The supplies will continue for 30 years starting in 2015.
Russia has welcomed Korea’s plans to bid for Russian oil and gas assets and build petrochemical projects and LNG plants in the Russian Far East. India has long been advised to follow the same winning formula – offer investment and technology in exchange for access to Russian energy resources – but has failed to achieve any breakthroughs since winning a stake in the Sakhalin-1 oil and gas field seven years ago.
Tuesday, September 30, 2008
Monday, September 29, 2008
Natural Gas Futures Down on Bailout Plan Uncertainty
Sept. 29 (Bloomberg) -- Natural gas futures declined in New York on concern a $700 billion U.S. government bailout plan for the financial industry may not be effective, threatening the economy and energy demand.
Industrial consumers, such as utilities and factories, might pare operations in a slowing economy, cutting demand for the fuel. A package was designed over the weekend and must now pass votes in the House and Senate.
``Without much idea what the economy will immediately look like, gas is just following crude and the rest of energy'' lower, said Lisa Zembrodt, commodity analyst at Summit Energy Services Inc. in Louisville, Kentucky. The package is ``the elephant in the room.''
Natural gas for November delivery fell 37.6 cents, or 4.9 percent, to $7.252 per million British thermal units at 12:04 p.m. on the New York Mercantile Exchange. The October contract expired Sept. 26. Natural gas has fallen 13 percent this month. Crude oil declined $7.73, or 7.2 percent, to $99.16 a barrel.
``People are concerned that the economy will go into the tank,'' said Ed Kennedy, a trader with Commercial Brokerage Corp. in Miami. The expectation is that ``crude and product demand will go down because of economic conditions.''
The U.S. economy expanded more slowly than earlier estimated in the second quarter, the Commerce Department said on Sept. 26. The annual rate of 2.8 percent was down from a preliminary estimate of 3.3 percent issued last month.
Industrial consumers, such as utilities and factories, might pare operations in a slowing economy, cutting demand for the fuel. A package was designed over the weekend and must now pass votes in the House and Senate.
``Without much idea what the economy will immediately look like, gas is just following crude and the rest of energy'' lower, said Lisa Zembrodt, commodity analyst at Summit Energy Services Inc. in Louisville, Kentucky. The package is ``the elephant in the room.''
Natural gas for November delivery fell 37.6 cents, or 4.9 percent, to $7.252 per million British thermal units at 12:04 p.m. on the New York Mercantile Exchange. The October contract expired Sept. 26. Natural gas has fallen 13 percent this month. Crude oil declined $7.73, or 7.2 percent, to $99.16 a barrel.
``People are concerned that the economy will go into the tank,'' said Ed Kennedy, a trader with Commercial Brokerage Corp. in Miami. The expectation is that ``crude and product demand will go down because of economic conditions.''
The U.S. economy expanded more slowly than earlier estimated in the second quarter, the Commerce Department said on Sept. 26. The annual rate of 2.8 percent was down from a preliminary estimate of 3.3 percent issued last month.
USA Natural Gas Surplus?
Crisis. What crisis?
Lost amid persistent worries about the price of crude oil and gasoline is a little-understood reality: There is more natural gas under our feet than we know what to do with.
Indeed, natural-gas production is growing at such a rapid rate in this country that it’s threatening to outrun demand — driving down prices and prompting producers to ponder capping wells or exporting the excess to Asia.
Industry figures show that more gas wells were completed in the United States during July than in any month in history. The Energy Information Administration now expects gas production, which remained essentially flat from 1999 to 2006, to surge 8 percent in 2008.
“It caught everyone by surprise,” said Kobi Platt, an analyst for the federal agency. “It’s been the one bright spot.”
In the near term, the boom in natural-gas production could save money for consumers who use it to heat their homes.
Over the long haul, though, the natural-gas boom could have profound implications in a country that now imports more than 60 percent of its crude oil — fueling a major rethink of how we generate electricity and move our cars and trucks.
A big plank in billionaire investor T. Boone Pickens’ much-touted energy plan is to use more natural gas for transportation as a way to reduce oil imports. The surge in natural-gas supplies makes the plan more feasible, although other obstacles remain, such as building an infrastructure that would dispense the fuel into cars and trucks.
Others would rather see more natural gas used to generate electricity. Natural gas is now used to generate about 21.5 percent of the nation’s electricity, while coal is still used to generate nearly half.
Sharon Buccino, a director at the Natural Resources Defense Council, said that a push for more natural gas in generating electricity would reduce our reliance on coal, which pollutes more than natural gas. The resulting electricity, in turn, could be used to charge batteries for electric cars, which would help reduce oil imports.
She said a long-term energy policy, however, needs to rely more on solutions such as energy conservation and renewable energy. Natural gas is still a fossil fuel, and there can be environmental damage in producing the fuel, she noted.
But “bottom line, it’s a good thing” that there is a good supply of natural gas, Buccino said.
Automakers such as General Motors Corp., which plans to introduce the Chevrolet Volt in 2010, also are looking ahead as they plan to sell electric vehicles.
GM spokesman Kyle Johnson said the automaker is collaborating with the Electric Power Research Institute to ensure that the electric grid will be able to deal with a growing number of electric vehicles.
“It’s a very important element in our plans,” he said.
Growing domestic supplies have already played a role in softening natural-gas prices, a trend that some analysts say could continue for another couple of years. The price for 1,000 cubic feet of gas on the New York Mercantile Exchange has been trading at just below $8, down sharply from a peak of $13.57 in early July.
Skip Horvath, president of the Natural Gas Supply Association, said that he expected supply and demand for natural gas to climb over the long haul for electric power generation and other uses.
“But that doesn’t mean there won’t be short-term fluctuations in price as a result of temporary imbalances between supply and demand,” he said.
Lost amid persistent worries about the price of crude oil and gasoline is a little-understood reality: There is more natural gas under our feet than we know what to do with.
Indeed, natural-gas production is growing at such a rapid rate in this country that it’s threatening to outrun demand — driving down prices and prompting producers to ponder capping wells or exporting the excess to Asia.
Industry figures show that more gas wells were completed in the United States during July than in any month in history. The Energy Information Administration now expects gas production, which remained essentially flat from 1999 to 2006, to surge 8 percent in 2008.
“It caught everyone by surprise,” said Kobi Platt, an analyst for the federal agency. “It’s been the one bright spot.”
In the near term, the boom in natural-gas production could save money for consumers who use it to heat their homes.
Over the long haul, though, the natural-gas boom could have profound implications in a country that now imports more than 60 percent of its crude oil — fueling a major rethink of how we generate electricity and move our cars and trucks.
A big plank in billionaire investor T. Boone Pickens’ much-touted energy plan is to use more natural gas for transportation as a way to reduce oil imports. The surge in natural-gas supplies makes the plan more feasible, although other obstacles remain, such as building an infrastructure that would dispense the fuel into cars and trucks.
Others would rather see more natural gas used to generate electricity. Natural gas is now used to generate about 21.5 percent of the nation’s electricity, while coal is still used to generate nearly half.
Sharon Buccino, a director at the Natural Resources Defense Council, said that a push for more natural gas in generating electricity would reduce our reliance on coal, which pollutes more than natural gas. The resulting electricity, in turn, could be used to charge batteries for electric cars, which would help reduce oil imports.
She said a long-term energy policy, however, needs to rely more on solutions such as energy conservation and renewable energy. Natural gas is still a fossil fuel, and there can be environmental damage in producing the fuel, she noted.
But “bottom line, it’s a good thing” that there is a good supply of natural gas, Buccino said.
Automakers such as General Motors Corp., which plans to introduce the Chevrolet Volt in 2010, also are looking ahead as they plan to sell electric vehicles.
GM spokesman Kyle Johnson said the automaker is collaborating with the Electric Power Research Institute to ensure that the electric grid will be able to deal with a growing number of electric vehicles.
“It’s a very important element in our plans,” he said.
Growing domestic supplies have already played a role in softening natural-gas prices, a trend that some analysts say could continue for another couple of years. The price for 1,000 cubic feet of gas on the New York Mercantile Exchange has been trading at just below $8, down sharply from a peak of $13.57 in early July.
Skip Horvath, president of the Natural Gas Supply Association, said that he expected supply and demand for natural gas to climb over the long haul for electric power generation and other uses.
“But that doesn’t mean there won’t be short-term fluctuations in price as a result of temporary imbalances between supply and demand,” he said.
Sunday, September 28, 2008
Citizen - Call Your Natural Gas Legislature
Back in August, I wrote about Mr. Pickens’s energy plan, which has itself been accompanied by a slick advertising campaign. The Pickens Plan — or Pickenomics, as I like to think of it — calls for a massive increase in the use of wind power for electricity generation, and for moving our car and truck fleets off of foreign oil and onto home-drilled natural gas.
Mr. Pickens’s $58 million campaign has included a Facebook presence, TV commercials, and an email list that has ignored repeated requests from me to unsubscribe.
Mr. Pickens has a big stake in Clean Energy Fuels, the country’s largest natural-gas fuels supplier, and it’s certainly no surprise that Chesapeake, a natural gas producer, has hopped on the bandwagon.
While less than one percent of vehicles in this country run on natural gas, Chesapeake would substantially pad its profits if it could persuade millions of consumers to drive with the fuel — and persuade the government to subsidize infrastructure investment to make that possible.
The Rise of Natural Gas Populism
By Kate Galbraith
Watching Sunday Night Football last weekend, I was intrigued to see an ad featuring Aubrey K. McClendon, the head of Chesapeake Energy, the largest independent gas producer in the country, intoning on the virtues of natural gas-fired cars.
Since the beginning of the month, readers may have also seen Mr. McClendon’s face peering out from advertisements in this newspaper, as well as The Washington Post, USA Today and The Wall Street Journal. “Let’s Rescue America’s Economy,” the ad states. “Demand Natural Gas Now!”
If it seems like Pickens redux, it’s not an accident. That’s Mr. McClendon below, in an ad posted at the Chesapeake-run Web site CNGnow.org, where the Pickens Plan is roundly endorsed.
What is interesting about the Pickens/Chesapeake twin campaigns is their direct, populist appeal. Most firms go to Washington to lobby for what they want, and there’s not doubt Mr. Pickens and Chesapeake are doing their measure of that.
But they are also spending millions of dollars doing things the old-fashioned way: taking their case over the heads of politicians and directly to the people — or more specifically, to consumers.
“We’re a producer of this stuff. We’re not in the business of building compressor units,” said Tom Price, a Chesapeake spokesman.
In other words, Chesapeake needs to find a way to reach ordinary Americans, who do not usually come into contact with the company. Chesapeake’s goal, said Mr. Price, is to “try to inspire the consumers themselves to make contact with their legislators and say, ‘Help us’!”
Mr. Pickens’s $58 million campaign has included a Facebook presence, TV commercials, and an email list that has ignored repeated requests from me to unsubscribe.
Mr. Pickens has a big stake in Clean Energy Fuels, the country’s largest natural-gas fuels supplier, and it’s certainly no surprise that Chesapeake, a natural gas producer, has hopped on the bandwagon.
While less than one percent of vehicles in this country run on natural gas, Chesapeake would substantially pad its profits if it could persuade millions of consumers to drive with the fuel — and persuade the government to subsidize infrastructure investment to make that possible.
The Rise of Natural Gas Populism
By Kate Galbraith
Watching Sunday Night Football last weekend, I was intrigued to see an ad featuring Aubrey K. McClendon, the head of Chesapeake Energy, the largest independent gas producer in the country, intoning on the virtues of natural gas-fired cars.
Since the beginning of the month, readers may have also seen Mr. McClendon’s face peering out from advertisements in this newspaper, as well as The Washington Post, USA Today and The Wall Street Journal. “Let’s Rescue America’s Economy,” the ad states. “Demand Natural Gas Now!”
If it seems like Pickens redux, it’s not an accident. That’s Mr. McClendon below, in an ad posted at the Chesapeake-run Web site CNGnow.org, where the Pickens Plan is roundly endorsed.
What is interesting about the Pickens/Chesapeake twin campaigns is their direct, populist appeal. Most firms go to Washington to lobby for what they want, and there’s not doubt Mr. Pickens and Chesapeake are doing their measure of that.
But they are also spending millions of dollars doing things the old-fashioned way: taking their case over the heads of politicians and directly to the people — or more specifically, to consumers.
“We’re a producer of this stuff. We’re not in the business of building compressor units,” said Tom Price, a Chesapeake spokesman.
In other words, Chesapeake needs to find a way to reach ordinary Americans, who do not usually come into contact with the company. Chesapeake’s goal, said Mr. Price, is to “try to inspire the consumers themselves to make contact with their legislators and say, ‘Help us’!”
Saturday, September 27, 2008
Japan Invests $20 Billion in Australian Natural Gas Proeject
INPEX, Japan's largest oil explorer, has picked Darwin as the site of a proposed $US20 billion ($24 billion) natural gas project that would be Japan's biggest investment in Australia.
Inpex and its partner, Total, will decide whether to build the Ichthys liquefied natural gas project late next year or early in 2010 and production could start in late 2014 or early 2015, the company said.
The partners dropped an earlier plan to build the plant off Western Australia, closer to the offshore gas field.
The fuel will be shipped to Japan, the world's largest liquefied natural gas consumer, where demand from power producers may rise 21 per cent by 2030.
Inpex's estimate of the cost of the project is more than double the latest estimate by the Northern Territory Government.
"Initial project costs may have grown by a few billion dollars to build a longer pipeline spanning the Ichthys field and terminating in Darwin, but rising LNG sale prices will easily help Inpex absorb incremental costs," said Lalita Gupta, an analyst at Morgan Stanley in Tokyo.
The partners would start initial plant engineering work soon, Inpex said. The plant will be designed initially to produce more than 8 million tonnes of liquefied natural gas a year, as well as 1.6 million tonnes of liquefied petroleum gas and 100,000 barrels a day of condensates, a type of light oil.
Should the Ichthys project go ahead, it would boost jobs and business opportunities in the Darwin region, said the Minister for Resources and Energy, Martin Ferguson.
"The reserves are sufficient to support a major LNG export project for decades to come," Mr Ferguson said. "I hope this project will be one of many established over the next few years as we continue to unlock the wealth from Australia's immense gas and energy resources."
Global consumption of liquefied natural gas is set to increase 10 per cent a year until 2015, more than five times the estimated gain in crude oil demand, as power generators switch to cleaner fuel.
The Ichthys project, which will have a life of at least 40 years, is one of about 10 proposed liquefied natural gas ventures in Australia, which has two operating plants and another under construction.
Earlier this year Inpex and Total started studying the Blaydin Point site near Darwin amid opposition from environmental groups to their originally preferred location on the Maret Islands off Western Australia, closer to the Ichthys field. The partners would have had to negotiate an agreement with local Aboriginal communities to build the plant in WA and would have had to supply some of the gas to the local market.
The selection of Darwin means they will need to build an 850-kilometre pipeline to transport gas, raising project costs.
Inpex owns 76 per cent of Ichthys, while Total, Europe's third-largest oil company, owns the rest.
Inpex and its partner, Total, will decide whether to build the Ichthys liquefied natural gas project late next year or early in 2010 and production could start in late 2014 or early 2015, the company said.
The partners dropped an earlier plan to build the plant off Western Australia, closer to the offshore gas field.
The fuel will be shipped to Japan, the world's largest liquefied natural gas consumer, where demand from power producers may rise 21 per cent by 2030.
Inpex's estimate of the cost of the project is more than double the latest estimate by the Northern Territory Government.
"Initial project costs may have grown by a few billion dollars to build a longer pipeline spanning the Ichthys field and terminating in Darwin, but rising LNG sale prices will easily help Inpex absorb incremental costs," said Lalita Gupta, an analyst at Morgan Stanley in Tokyo.
The partners would start initial plant engineering work soon, Inpex said. The plant will be designed initially to produce more than 8 million tonnes of liquefied natural gas a year, as well as 1.6 million tonnes of liquefied petroleum gas and 100,000 barrels a day of condensates, a type of light oil.
Should the Ichthys project go ahead, it would boost jobs and business opportunities in the Darwin region, said the Minister for Resources and Energy, Martin Ferguson.
"The reserves are sufficient to support a major LNG export project for decades to come," Mr Ferguson said. "I hope this project will be one of many established over the next few years as we continue to unlock the wealth from Australia's immense gas and energy resources."
Global consumption of liquefied natural gas is set to increase 10 per cent a year until 2015, more than five times the estimated gain in crude oil demand, as power generators switch to cleaner fuel.
The Ichthys project, which will have a life of at least 40 years, is one of about 10 proposed liquefied natural gas ventures in Australia, which has two operating plants and another under construction.
Earlier this year Inpex and Total started studying the Blaydin Point site near Darwin amid opposition from environmental groups to their originally preferred location on the Maret Islands off Western Australia, closer to the Ichthys field. The partners would have had to negotiate an agreement with local Aboriginal communities to build the plant in WA and would have had to supply some of the gas to the local market.
The selection of Darwin means they will need to build an 850-kilometre pipeline to transport gas, raising project costs.
Inpex owns 76 per cent of Ichthys, while Total, Europe's third-largest oil company, owns the rest.
Friday, September 26, 2008
Natural Gas Drilling in Eastern Ohio, USA
Capital City Energy Group Inc. is planning to begin drilling for natural gas in eastern Ohio early next year.
The Columbus-based company said its Avanti Energy Partners LLC subsidiary expects a five-well natural gas drilling program to begin in the first quarter of 2009. It will target what’s known as the Clinton sandstone in the Appalachian Basin.
The company said other wells in the area it will drill have produced an average of about 35 million cubic feet of natural gas per well during their first year of production. Each well is expected to produce about 175 million cubic feet of natural gas in all, the company said.
Based on estimated output and on current natural gas prices, 25 wells would generate $7.5 million in annual revenue. Avanti wants to put 250 wells in the area and is working on securing 2,000 to 3,000 acres of land to do it.
“The economics of drilling wells in the Appalachian Basin combined with the high price of commodities make drilling in our own backyard very attractive,” Capital City CEO Timothy Crawford said in a news release.
Capital City Energy (OTCBB: CETG) manages energy-related investment funds and invests in energy-related production and development companies such as drillers, operators and pipeline owners. It turned a profit of $188,000 on $2.9 million in revenue last year.
The Columbus-based company said its Avanti Energy Partners LLC subsidiary expects a five-well natural gas drilling program to begin in the first quarter of 2009. It will target what’s known as the Clinton sandstone in the Appalachian Basin.
The company said other wells in the area it will drill have produced an average of about 35 million cubic feet of natural gas per well during their first year of production. Each well is expected to produce about 175 million cubic feet of natural gas in all, the company said.
Based on estimated output and on current natural gas prices, 25 wells would generate $7.5 million in annual revenue. Avanti wants to put 250 wells in the area and is working on securing 2,000 to 3,000 acres of land to do it.
“The economics of drilling wells in the Appalachian Basin combined with the high price of commodities make drilling in our own backyard very attractive,” Capital City CEO Timothy Crawford said in a news release.
Capital City Energy (OTCBB: CETG) manages energy-related investment funds and invests in energy-related production and development companies such as drillers, operators and pipeline owners. It turned a profit of $188,000 on $2.9 million in revenue last year.
Thursday, September 25, 2008
Toyota Looking at Natural Gas Automobiles
Toyota is dipping its toe in the natural-gas well.
The Japanese automaker said today that it plans to unveil a concept version of a compressed-natural-gas-powered Camry hybrid sedan at the L.A. Auto Show in November.
Toyota isn’t making any promises about when the CNG-powered hybrid car will arrive on dealer lots — if ever.
“We just decided from a concept perspective to put this out and take a look at CNG as another viable [alternative fuel] option” said Jana Hartline, a spokeswoman for the automaker.
Toyota is arriving a bit late to the CNG game. Honda has been selling out its 1,000-a-year production run of CNG-fueled Civics in recent years, and plans to double production for the 2009 model year to 2,000 cars.
The Civic GX is selling out even though its base sticker of around $25,000 represents a substantial premium over the comparable Civic LX ($18,155) or the even the Civic hybrid ($23,550).
In addition, finding fuel remains problematic. A government website that helps you locate alt-fuel outlets lists 94 CNG fueling stations within a 100-mile radius of downtown L.A., but many of those serve only government or corporate fleets and aren’t open to the public.
So what’s the attraction? Well, for one thing, CNG sells for the equivalent of $2 to $2.50 a gallon in Southern California. Not bad when regular gasoline is going for an average of $3.72 a gallon statewide. And with combined city/highway mileage of 28 mpg, the GX burns that cheap fuel at only a slightly faster rate than the regular Civic; the Civic hybrid, by contrast, gets 42 combined mpg.
Then there’s the $4,000 federal income tax credit, available at a time when tax credits on the most popular hybrids are going or gone altogether. And as you might have heard, GX owners are still eligible for carpool lane stickers in California.
Meanwhile, it wouldn’t hurt for Toyota to have something in the works in case voters approve Prop 10, the controversial ballot initiative backed by Texas oil billionaire T. Boone Pickens that could provide $10,000 rebates for purchasers of natural-gas-powered cars. (Pickens says Prop 10 will help put us on the road to energy independence; an L.A. Times editorial called it a “reprehensible scam.”)
But in the short term, at least, the potential market for CNG vehicles remains relatively small, which could explain Toyota’s cautious approach to what is a fairly well-proven technology. (Toyota actually offered a CNG-powered Camry for the 2000 model year, “but nobody bit,” Hartline said.)
California and New York are the only states where Honda puts any real sales muscle behind the GX. And even Honda concedes that driving one across country would require “very careful planning” to avoid that dreaded gasless feeling.
Toyota clearly remains committed to its hybrid "synergy drive" -- whether powered by gasoline, compressed natural gas or cold fusion -- as its green powertrain of choice for the immediate future.
The company continues to hint at plans to extend its segment-leading Prius brand name beyond its current five-door hatchback version. (A Prius minivan, anyone?) And in yet another announcement today, the company said it will cut the price of replacement batteries for both first- and second- generation Priuses by more than 10%.
The nickel metal hydride batteries for the 2000-03 versions will now go for $2,299; batteries for the 2004-2008 model have been reduced to $2,588. Batteries for both versions previously sold for $2,985.
California regulators require Toyota to offer hefty warranties on these batteries — eight years or 100,000 miles on the first generation and 10 years or 150,000 miles on the second gen. But Toyota and outside battery experts say failures have been rare, despite the dire warnings from early skeptics that unreliable batteries would be the downfall of hybrids.
“It is truly accurate to say that they are batteries that last the lifetime of the car,” said Felix Kramer, founder of CalCars.org, a Palo Alto-based advocacy group.
As the total number of Priuses sold in the U.S. surpasses 550,000, Toyota also said it may begin refurbishing NiMH batteries in North America to further lower replacement costs.
The Japanese automaker said today that it plans to unveil a concept version of a compressed-natural-gas-powered Camry hybrid sedan at the L.A. Auto Show in November.
Toyota isn’t making any promises about when the CNG-powered hybrid car will arrive on dealer lots — if ever.
“We just decided from a concept perspective to put this out and take a look at CNG as another viable [alternative fuel] option” said Jana Hartline, a spokeswoman for the automaker.
Toyota is arriving a bit late to the CNG game. Honda has been selling out its 1,000-a-year production run of CNG-fueled Civics in recent years, and plans to double production for the 2009 model year to 2,000 cars.
The Civic GX is selling out even though its base sticker of around $25,000 represents a substantial premium over the comparable Civic LX ($18,155) or the even the Civic hybrid ($23,550).
In addition, finding fuel remains problematic. A government website that helps you locate alt-fuel outlets lists 94 CNG fueling stations within a 100-mile radius of downtown L.A., but many of those serve only government or corporate fleets and aren’t open to the public.
So what’s the attraction? Well, for one thing, CNG sells for the equivalent of $2 to $2.50 a gallon in Southern California. Not bad when regular gasoline is going for an average of $3.72 a gallon statewide. And with combined city/highway mileage of 28 mpg, the GX burns that cheap fuel at only a slightly faster rate than the regular Civic; the Civic hybrid, by contrast, gets 42 combined mpg.
Then there’s the $4,000 federal income tax credit, available at a time when tax credits on the most popular hybrids are going or gone altogether. And as you might have heard, GX owners are still eligible for carpool lane stickers in California.
Meanwhile, it wouldn’t hurt for Toyota to have something in the works in case voters approve Prop 10, the controversial ballot initiative backed by Texas oil billionaire T. Boone Pickens that could provide $10,000 rebates for purchasers of natural-gas-powered cars. (Pickens says Prop 10 will help put us on the road to energy independence; an L.A. Times editorial called it a “reprehensible scam.”)
But in the short term, at least, the potential market for CNG vehicles remains relatively small, which could explain Toyota’s cautious approach to what is a fairly well-proven technology. (Toyota actually offered a CNG-powered Camry for the 2000 model year, “but nobody bit,” Hartline said.)
California and New York are the only states where Honda puts any real sales muscle behind the GX. And even Honda concedes that driving one across country would require “very careful planning” to avoid that dreaded gasless feeling.
Toyota clearly remains committed to its hybrid "synergy drive" -- whether powered by gasoline, compressed natural gas or cold fusion -- as its green powertrain of choice for the immediate future.
The company continues to hint at plans to extend its segment-leading Prius brand name beyond its current five-door hatchback version. (A Prius minivan, anyone?) And in yet another announcement today, the company said it will cut the price of replacement batteries for both first- and second- generation Priuses by more than 10%.
The nickel metal hydride batteries for the 2000-03 versions will now go for $2,299; batteries for the 2004-2008 model have been reduced to $2,588. Batteries for both versions previously sold for $2,985.
California regulators require Toyota to offer hefty warranties on these batteries — eight years or 100,000 miles on the first generation and 10 years or 150,000 miles on the second gen. But Toyota and outside battery experts say failures have been rare, despite the dire warnings from early skeptics that unreliable batteries would be the downfall of hybrids.
“It is truly accurate to say that they are batteries that last the lifetime of the car,” said Felix Kramer, founder of CalCars.org, a Palo Alto-based advocacy group.
As the total number of Priuses sold in the U.S. surpasses 550,000, Toyota also said it may begin refurbishing NiMH batteries in North America to further lower replacement costs.
Horizontal Natural Gas Drilling in the Marcellus Shale
WILLIAMSPORT, Pa., Sept 24, 2008 /PRNewswire via COMTEX/ -- -Union Drilling Rig #58 is a first-of-its-kind drilling rig designed for drilling in Appalachia and the Marcellus Shale- Chief Oil & Gas and Union Drilling, Inc. unveiled the new AC QuickSilver drilling system in Lycoming County, Pennsylvania, the first-of-its-kind rig designed for horizontal natural gas drilling in the Marcellus Shale.
"This is an exciting time for Chief Oil & Gas and the Commonwealth of Pennsylvania," said William Buckler, Senior Vice President of Operations for Chief Oil & Gas. "Development of the Marcellus Shale is good for Pennsylvania and good for the environment. Natural gas is one of the cleanest fuel choices for electric generation, heating and transportation. This new drilling system and its cutting-edge technologies will enable Chief to efficiently and cost-effectively develop the rich natural gas deposits in the Marcellus Shale."
Development of the Marcellus Shale is expected to provide a significant boost to Pennsylvania's economy. According to Penn State's Workforce Education and Development Initiative, production of natural gas in the Marcellus Shale will bring increased revenue and new jobs. Gross state product would increase by more than $500 million a year. For every $1 billion in royalty income paid to Pennsylvania residents, nearly 8,000 jobs will be created annually. And the economic benefits will have a rippling effect across Pennsylvania providing money for new businesses, schools and roads.
Scientists estimate that the Marcellus Shale holds 500 trillion cubic feet of clean natural gas. If even 10 percent of it is recovered, it could supply all of America's natural gas needs for two years.
"This is a landmark day for Lycoming County and Pennsylvania. This brand new drilling rig represents a significant economic investment in our community, including new jobs and opportunities for local businesses," said Rebecca A. Burke, Chairperson, Lycoming County Commissioners.
This is the first of several new-build rigs planned by Chief Oil & Gas for the Marcellus Shale region. The next new rig is expected to go into operation in early spring 2009. Chief expects to have six drilling rigs running in the Marcellus Shale by the end of 2009.
The 1600 horsepower rig is built by Houston-based IDM Group, operated by Union Drilling, Inc. and is under a three-year contract for use by Chief Oil & Gas.
Christopher D. Strong, Union Drilling's President and Chief Executive Officer, stated, "We are very pleased to unveil this new technology for Marcellus Shale drilling. This new rig design is especially well-suited for Appalachia's rugged terrain and the 'Quick-Move' technology will allow Chief to rig down, then rig up on a new location within 100 miles, in less than 48 hours. It also allows for faster, more efficient drilling and has the capability to drill longer horizontal laterals."
The rig also employs QuickSkid technology which allows for more efficient drilling of multiple wells from one pad site, reducing the impact on the environment.
To remove the natural gas from the Marcellus Shale, the well is drilled straight down, or vertically, more than a mile below the surface and then turned to drill horizontally into the shale. After the drilling is complete, water and sand are pumped into the well causing small fractures in the shale to release the gas, a process called hydraulic fracturing or "fracing," allowing the gas to be collected through a system of pipelines that take the gas to needed markets.
Chief has worked closely with Pennsylvania officials, the Department of Environmental Protection and the Susquehanna River Basin Commission to ensure that drilling is conducted in a way that will not have a detrimental impact on the state's natural resources.
"Chief has been drilling and producing clean natural gas from shale for more than a decade, and we are proud of our environmental record. We are committed to protecting the ecological integrity of Pennsylvania's resources," said Buckler.
The Marcellus Shale runs from the southern tier of New York, through the western portion of Pennsylvania into the eastern half of Ohio and through West Virginia. In Pennsylvania, the formation extends from the Appalachian plateau into the western valley and ridge.
"This is an exciting time for Chief Oil & Gas and the Commonwealth of Pennsylvania," said William Buckler, Senior Vice President of Operations for Chief Oil & Gas. "Development of the Marcellus Shale is good for Pennsylvania and good for the environment. Natural gas is one of the cleanest fuel choices for electric generation, heating and transportation. This new drilling system and its cutting-edge technologies will enable Chief to efficiently and cost-effectively develop the rich natural gas deposits in the Marcellus Shale."
Development of the Marcellus Shale is expected to provide a significant boost to Pennsylvania's economy. According to Penn State's Workforce Education and Development Initiative, production of natural gas in the Marcellus Shale will bring increased revenue and new jobs. Gross state product would increase by more than $500 million a year. For every $1 billion in royalty income paid to Pennsylvania residents, nearly 8,000 jobs will be created annually. And the economic benefits will have a rippling effect across Pennsylvania providing money for new businesses, schools and roads.
Scientists estimate that the Marcellus Shale holds 500 trillion cubic feet of clean natural gas. If even 10 percent of it is recovered, it could supply all of America's natural gas needs for two years.
"This is a landmark day for Lycoming County and Pennsylvania. This brand new drilling rig represents a significant economic investment in our community, including new jobs and opportunities for local businesses," said Rebecca A. Burke, Chairperson, Lycoming County Commissioners.
This is the first of several new-build rigs planned by Chief Oil & Gas for the Marcellus Shale region. The next new rig is expected to go into operation in early spring 2009. Chief expects to have six drilling rigs running in the Marcellus Shale by the end of 2009.
The 1600 horsepower rig is built by Houston-based IDM Group, operated by Union Drilling, Inc. and is under a three-year contract for use by Chief Oil & Gas.
Christopher D. Strong, Union Drilling's President and Chief Executive Officer, stated, "We are very pleased to unveil this new technology for Marcellus Shale drilling. This new rig design is especially well-suited for Appalachia's rugged terrain and the 'Quick-Move' technology will allow Chief to rig down, then rig up on a new location within 100 miles, in less than 48 hours. It also allows for faster, more efficient drilling and has the capability to drill longer horizontal laterals."
The rig also employs QuickSkid technology which allows for more efficient drilling of multiple wells from one pad site, reducing the impact on the environment.
To remove the natural gas from the Marcellus Shale, the well is drilled straight down, or vertically, more than a mile below the surface and then turned to drill horizontally into the shale. After the drilling is complete, water and sand are pumped into the well causing small fractures in the shale to release the gas, a process called hydraulic fracturing or "fracing," allowing the gas to be collected through a system of pipelines that take the gas to needed markets.
Chief has worked closely with Pennsylvania officials, the Department of Environmental Protection and the Susquehanna River Basin Commission to ensure that drilling is conducted in a way that will not have a detrimental impact on the state's natural resources.
"Chief has been drilling and producing clean natural gas from shale for more than a decade, and we are proud of our environmental record. We are committed to protecting the ecological integrity of Pennsylvania's resources," said Buckler.
The Marcellus Shale runs from the southern tier of New York, through the western portion of Pennsylvania into the eastern half of Ohio and through West Virginia. In Pennsylvania, the formation extends from the Appalachian plateau into the western valley and ridge.
Wednesday, September 24, 2008
Oklahoma Gas & Electric forms new JV for Natural Gas
OKLAHOMA CITY and DALLAS, Sept 23, 2008 /PRNewswire-FirstCall via COMTEX/ -- OGE Energy Corp. (OGE:
Oklahoma Gas and Electric Company
News, chart, profile, more
Last: 31.80+0.37+1.18%
OGE 31.80, +0.37, +1.2%) and Energy Transfer Partners, L.P. (ETP:
energy transfer prtnrs l p unit ltd partn
News, chart, profile, more
Last: 36.13-0.65-1.77%
4:02pm 09/23/2008
Delayed quote data
Add to portfolio
Analyst
Create alert
Insider
Discuss
Financials
Sponsored by:
ETP 36.13, -0.65, -1.8%) announced today that the parties have entered into an agreement to form a joint venture combining OGE's Enogex midstream business with ETP's interstate operations as well as its midstream operations in the Rocky Mountains. The transaction will create a joint venture with diverse business lines and an expansive geographic platform to pursue growth opportunities in midstream and interstate natural gas pipeline operations.
The joint venture, ETP Enogex Partners LLC, will be jointly owned and managed by ETP and OGE on a 50/50 basis. The parties are contractually obligated to take various actions to facilitate an initial public offering of ETP Enogex Partners following the closing of the transaction, including the creation of a master limited partnership structure.
"The combination of Enogex's midstream and ETP's interstate assets creates a very diverse and competitive business," said Pete Delaney, OGE Energy chairman, president and CEO. "Our partnership will offer producers a variety of markets for their gas. Additionally, Transwestern's and MEP's long-term contracts provide an excellent complement to Enogex's gathering and processing assets."
"The partnership between Energy Transfer and Enogex allows us to expand our supply base into the prolific natural gas basins in Oklahoma, enabling the partnership to enhance growth opportunities throughout our pipeline systems," said Kelcy Warren, ETP's chairman and CEO. "By combining Enogex's supply base with Transwestern's and MEP's market access, this transaction should prove to be very successful for both parties.
"OGE will contribute to ETP Enogex Partners 100 percent of its ownership interest in Enogex LLC and ETP will contribute 100 percent of its ownership interests in Transwestern Pipeline Company, LLC and ETC Canyon Pipeline, LLC and its 50 percent interest in Midcontinent Express Pipeline, LLC.
OGE Energy has scheduled a conference call webcast, hosted by Pete Delaney, to discuss today's announcement. It can be accessed at 10 a.m. eastern time today via http://www.oge.com. Energy Transfer will host a conference call, which is scheduled for noon eastern time and the dial-in number is 1-800-230-1092.
ETP Enogex Partners will initially be led by an executive management team including Delaney and Warren; Danny Harris, senior vice president and chief operating officer of OGE Energy; and Mackie McCrea, president and chief operating officer of ETP.
OGE and ETP expect to complete the formation of the joint venture after obtaining satisfactory financing, customary regulatory approvals and various third-party consents.
OGE Energy Corp. was advised by UBS Investment Bank, and Energy Transfer was advised by Credit Suisse.
Enogex operates a pipeline system engaged in natural gas gathering, compression, treating, dehydration, processing, transportation and storage. The Enogex system, located principally in Oklahoma, includes approximately 2,300 miles of natural gas transmission pipe and two storage facilities with total 2007 throughput of 1.52 billion cubic feet per day, connecting to 11 different intrastate and interstate pipelines at 64 interconnection points. The storage fields have working gas capacity of 23 billion cubic feet. Enogex has 175,000 horsepower of transmission compression.
The Enogex gathering system has more than 5,534 miles of pipeline with connections to approximately 3,100 wells and 250 central receipt points, plus six active processing plants, with 723 million cubic feet per day of inlet capacity, and a 50 percent interest in an additional processing plant with 20 million cubic feet per day of inlet capacity. Enogex has 225,000 horsepower of owned gathering and processing compression.
Transwestern operates a pipeline system geographically positioned to access markets in the Mid-Continent and Texas as well as the growing markets of California, Arizona, New Mexico and southern Nevada, with 2,648 miles of natural gas transmission pipelines with total 2007 throughput of 1.8 billion cubic feet per day, 19 interconnection points with interstate and intrastate pipelines and 347,745 horsepower of compression.
ETC Canyon Pipeline operates a pipeline system with more than 1,300 miles of natural gas gathering pipelines in Utah and Colorado with 193 million cubic feet per day of capacity as currently configured; 300 million cubic feet per day with added compression and processing. Canyon has six processing plants for natural gas liquids extraction and treating, with 90 million cubic feet per day of capacity and two NGL injection points on Enterprise Mid-Continent Pipeline, four interstate interconnects with Questar, Northwest, Source Gas and TransColorado. The Piceance Basin has production of 2.2 billion cubic feet of which 1.1 billion cubic feet is from the Canyon Corridor; total potential Basin reserves are estimated at 45.4 trillion cubic feet.
Midcontinent Express is a 50/50 joint venture between ETP and Kinder Morgan Energy Partners, L.P. with completion expected in the second quarter of 2009 of a 500-mile FERC regulated pipeline originating at an Enogex connection near Bennington, Okla., routing through Perryville, La. and terminating at an interconnect with Transco in Butler, Ala. Initial capacity is estimated at 1.5 billion cubic feet per day.
This news release does not constitute an offer to sell or a solicitation of an offer to buy any securities described herein, nor shall there be any sale of such securities in any state or jurisdiction in which such an offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. Any such offering may be made only by means of a prospectus.
Portions of this announcement may constitute "forward-looking statements" as defined by federal law. Although OGE and ETP believe any such statements are based on reasonable assumptions, there is no assurance that actual outcomes will not be materially different. Any such statements are made in reliance on the "Safe Harbor" protections provided under the Private Securities Reform Act of 1995. Additional information about issues that could lead to material changes in performance is contained in OGE's and ETP's annual reports filed with the Securities and Exchange Commission.
Oklahoma Gas and Electric Company
News, chart, profile, more
Last: 31.80+0.37+1.18%
OGE 31.80, +0.37, +1.2%) and Energy Transfer Partners, L.P. (ETP:
energy transfer prtnrs l p unit ltd partn
News, chart, profile, more
Last: 36.13-0.65-1.77%
4:02pm 09/23/2008
Delayed quote data
Add to portfolio
Analyst
Create alert
Insider
Discuss
Financials
Sponsored by:
ETP 36.13, -0.65, -1.8%) announced today that the parties have entered into an agreement to form a joint venture combining OGE's Enogex midstream business with ETP's interstate operations as well as its midstream operations in the Rocky Mountains. The transaction will create a joint venture with diverse business lines and an expansive geographic platform to pursue growth opportunities in midstream and interstate natural gas pipeline operations.
The joint venture, ETP Enogex Partners LLC, will be jointly owned and managed by ETP and OGE on a 50/50 basis. The parties are contractually obligated to take various actions to facilitate an initial public offering of ETP Enogex Partners following the closing of the transaction, including the creation of a master limited partnership structure.
"The combination of Enogex's midstream and ETP's interstate assets creates a very diverse and competitive business," said Pete Delaney, OGE Energy chairman, president and CEO. "Our partnership will offer producers a variety of markets for their gas. Additionally, Transwestern's and MEP's long-term contracts provide an excellent complement to Enogex's gathering and processing assets."
"The partnership between Energy Transfer and Enogex allows us to expand our supply base into the prolific natural gas basins in Oklahoma, enabling the partnership to enhance growth opportunities throughout our pipeline systems," said Kelcy Warren, ETP's chairman and CEO. "By combining Enogex's supply base with Transwestern's and MEP's market access, this transaction should prove to be very successful for both parties.
"OGE will contribute to ETP Enogex Partners 100 percent of its ownership interest in Enogex LLC and ETP will contribute 100 percent of its ownership interests in Transwestern Pipeline Company, LLC and ETC Canyon Pipeline, LLC and its 50 percent interest in Midcontinent Express Pipeline, LLC.
OGE Energy has scheduled a conference call webcast, hosted by Pete Delaney, to discuss today's announcement. It can be accessed at 10 a.m. eastern time today via http://www.oge.com. Energy Transfer will host a conference call, which is scheduled for noon eastern time and the dial-in number is 1-800-230-1092.
ETP Enogex Partners will initially be led by an executive management team including Delaney and Warren; Danny Harris, senior vice president and chief operating officer of OGE Energy; and Mackie McCrea, president and chief operating officer of ETP.
OGE and ETP expect to complete the formation of the joint venture after obtaining satisfactory financing, customary regulatory approvals and various third-party consents.
OGE Energy Corp. was advised by UBS Investment Bank, and Energy Transfer was advised by Credit Suisse.
Enogex operates a pipeline system engaged in natural gas gathering, compression, treating, dehydration, processing, transportation and storage. The Enogex system, located principally in Oklahoma, includes approximately 2,300 miles of natural gas transmission pipe and two storage facilities with total 2007 throughput of 1.52 billion cubic feet per day, connecting to 11 different intrastate and interstate pipelines at 64 interconnection points. The storage fields have working gas capacity of 23 billion cubic feet. Enogex has 175,000 horsepower of transmission compression.
The Enogex gathering system has more than 5,534 miles of pipeline with connections to approximately 3,100 wells and 250 central receipt points, plus six active processing plants, with 723 million cubic feet per day of inlet capacity, and a 50 percent interest in an additional processing plant with 20 million cubic feet per day of inlet capacity. Enogex has 225,000 horsepower of owned gathering and processing compression.
Transwestern operates a pipeline system geographically positioned to access markets in the Mid-Continent and Texas as well as the growing markets of California, Arizona, New Mexico and southern Nevada, with 2,648 miles of natural gas transmission pipelines with total 2007 throughput of 1.8 billion cubic feet per day, 19 interconnection points with interstate and intrastate pipelines and 347,745 horsepower of compression.
ETC Canyon Pipeline operates a pipeline system with more than 1,300 miles of natural gas gathering pipelines in Utah and Colorado with 193 million cubic feet per day of capacity as currently configured; 300 million cubic feet per day with added compression and processing. Canyon has six processing plants for natural gas liquids extraction and treating, with 90 million cubic feet per day of capacity and two NGL injection points on Enterprise Mid-Continent Pipeline, four interstate interconnects with Questar, Northwest, Source Gas and TransColorado. The Piceance Basin has production of 2.2 billion cubic feet of which 1.1 billion cubic feet is from the Canyon Corridor; total potential Basin reserves are estimated at 45.4 trillion cubic feet.
Midcontinent Express is a 50/50 joint venture between ETP and Kinder Morgan Energy Partners, L.P. with completion expected in the second quarter of 2009 of a 500-mile FERC regulated pipeline originating at an Enogex connection near Bennington, Okla., routing through Perryville, La. and terminating at an interconnect with Transco in Butler, Ala. Initial capacity is estimated at 1.5 billion cubic feet per day.
This news release does not constitute an offer to sell or a solicitation of an offer to buy any securities described herein, nor shall there be any sale of such securities in any state or jurisdiction in which such an offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. Any such offering may be made only by means of a prospectus.
Portions of this announcement may constitute "forward-looking statements" as defined by federal law. Although OGE and ETP believe any such statements are based on reasonable assumptions, there is no assurance that actual outcomes will not be materially different. Any such statements are made in reliance on the "Safe Harbor" protections provided under the Private Securities Reform Act of 1995. Additional information about issues that could lead to material changes in performance is contained in OGE's and ETP's annual reports filed with the Securities and Exchange Commission.
Tuesday, September 23, 2008
Majority of Natural Gas Production in Gulf of Mexico Still Down
Sept. 23 (Bloomberg) -- Royal Dutch Shell Plc, Europe's largest oil company, said it's preparing to step up production at its facilities in the Gulf of Mexico following Hurricane Ike.
Gross production at Shell-operated facilities stands at about 32,000 barrels of oil equivalent a day after 1,210 personnel were returned to offshore facilities, The Hague-based company said today in an e-mailed statement.
``Production ramp-up at remaining facilities will vary, depending on repairs and downstream oil and gas infrastructure readiness,'' Shell said. Production has increased ``slightly'' over the weekend, Shell added in the statement.
Hurricane Ike, the most recent storm to blast through the U.S. Gulf, made landfall in Texas on Sept. 13, cutting off power and damaging some refineries. Ike came less than two weeks after Hurricane Gustav made landfall in Louisiana. The storms flooded parts of the region, snarling oil production and forcing the evacuation of platforms offshore and installations onshore.
U.S. energy producers resumed output for about 23 percent of oil and 34 percent of natural-gas production in the Gulf of Mexico after the storms, the Minerals Management Service said yesterday in a statement on its Web site.
Energy companies reported that 7 rigs and 225 production platforms remain evacuated after this month's storms, the agency added. About 1 million barrels of daily oil production remains shut-in, along with 4.85 billion cubic feet of gas.
The Gulf of Mexico accounts for 26 percent of U.S. oil production and 14 percent of natural-gas output. The Gulf produces 1.3 million barrels of oil and an estimated 7.4 billion cubic feet of gas a day, according to the agency, which is part of the U.S. Interior Department.
Shell's normal average net production in the Gulf of Mexico is 370,000 barrels of oil equivalent a day and the company holds an interest in more than 459 offshore leases, according to Shell's Web site. Production in the Gulf of Mexico accounts for more than 80 percent of the company's overall U.S. production.
Gross production at Shell-operated facilities stands at about 32,000 barrels of oil equivalent a day after 1,210 personnel were returned to offshore facilities, The Hague-based company said today in an e-mailed statement.
``Production ramp-up at remaining facilities will vary, depending on repairs and downstream oil and gas infrastructure readiness,'' Shell said. Production has increased ``slightly'' over the weekend, Shell added in the statement.
Hurricane Ike, the most recent storm to blast through the U.S. Gulf, made landfall in Texas on Sept. 13, cutting off power and damaging some refineries. Ike came less than two weeks after Hurricane Gustav made landfall in Louisiana. The storms flooded parts of the region, snarling oil production and forcing the evacuation of platforms offshore and installations onshore.
U.S. energy producers resumed output for about 23 percent of oil and 34 percent of natural-gas production in the Gulf of Mexico after the storms, the Minerals Management Service said yesterday in a statement on its Web site.
Energy companies reported that 7 rigs and 225 production platforms remain evacuated after this month's storms, the agency added. About 1 million barrels of daily oil production remains shut-in, along with 4.85 billion cubic feet of gas.
The Gulf of Mexico accounts for 26 percent of U.S. oil production and 14 percent of natural-gas output. The Gulf produces 1.3 million barrels of oil and an estimated 7.4 billion cubic feet of gas a day, according to the agency, which is part of the U.S. Interior Department.
Shell's normal average net production in the Gulf of Mexico is 370,000 barrels of oil equivalent a day and the company holds an interest in more than 459 offshore leases, according to Shell's Web site. Production in the Gulf of Mexico accounts for more than 80 percent of the company's overall U.S. production.
Iraq & Shell Sign Natural Gas Deal
BAGHDAD: Iraq and Royal Dutch Shell PLC signed a deal to establish a joint venture that will tap natural gas in southern Iraq, the government said Monday.
Iraqi Oil Minister Hussein al-Shahristani and four executives from the Anglo-Dutch company signed the deal, Iraq's second with a foreign company since the U.S.-led invasion in 2003.
The joint venture with the state-run Iraqi South Oil Co. will invest in natural gas in the southern oil-rich province of Basra, Oil Ministry spokesman Assem Jihad said. Work will start early next month.
Iraq will hold 51 percent in the venture and Shell 49 percent.
Some of the extracted gas will cover domestic needs in power stations and factories, while the majority will be bought by Shell at market prices and exported, Jihad said.
Iraqi Oil Minister Hussein al-Shahristani and four executives from the Anglo-Dutch company signed the deal, Iraq's second with a foreign company since the U.S.-led invasion in 2003.
The joint venture with the state-run Iraqi South Oil Co. will invest in natural gas in the southern oil-rich province of Basra, Oil Ministry spokesman Assem Jihad said. Work will start early next month.
Iraq will hold 51 percent in the venture and Shell 49 percent.
Some of the extracted gas will cover domestic needs in power stations and factories, while the majority will be bought by Shell at market prices and exported, Jihad said.
Monday, September 22, 2008
India's First Deep Water Natural Gas Well Open
MUMBAI, India — Mukesh Ambani, one of the world's richest men, held a large beaker of greenish sludge in his hands, the first drops of light sweet crude that his company, Reliance Industries Ltd., has pulled from deep beneath the Bay of Bengal.
That sludge, Ambani says, is India's ticket to energy independence and Reliance's entry into the club of global energy majors.
"This accomplishment marks a strategic and emotional inflection point for every Indian. It proves that we can disprove the naysayers of the world, who had written off India's ability to produce its own oil and gas," he said Sunday.
Reliance has started production as global oil majors are facing diminishing new discoveries.
Pulling oil from 2,400 metres beneath the cyclone-prone, choppy waters of the Bay of Bengal is a technological feat, the sort of high-tech, high-cost deep-water drilling that was once the province of just a few of the world's top oil companies.
It also comes at a propitious time for India, the world's fifth-largest energy consumer. The country imports about three quarters of its oil and has been staggering under growing oil and gas import costs and an onerous oil subsidy bill.
Within 18 months, oil and gas production from block D6 of the Krishna Godavari basin will increase India's domestic production by 40 per cent, potentially shaving about $20 billion US from the nation's $77 billion oil import bill, according to Reliance officials.
The company says the 7,650 square-kilometre block holds 2.5 billion barrels of oil equivalent, 80 per cent to 85 per cent of it natural gas.
Canada's Niko Resources Ltd. (TSX:NKO), which has a 10 per cent stake in the project, and Reliance, India's largest company by market capitalization, have invested $8.7 billion in developing the block.
India still ranks low on the list of oil-producing countries, and the find is unlikely to put a big dent in global demand for oil, which the International Energy Agency pegs at 86.8 million barrels per day.
But Reliance insists this is just the beginning. "India is not short of hydrocarbons. It just hasn't been explored well," P.M.S. Prasad, president of Reliance's oil and gas division, said Sunday.
Reliance controls 40 exploration blocks in India, including several more in the Krishna Godavari basin.
Ambani called the start of production a "major victory" for India in its battle for energy security. "We can now confidently look forward to production from a series of other fields," he said.
First, however, Reliance must resolve a very Indian problem: An increasingly high-profile fraternal dispute which pits Mukesh Ambani against his younger brother Anil, who has sued Reliance Industries over the gas deposits.
Until that litigation is resolved, Reliance Industries, which expects to start natural gas production in January, can't sell a cubic metre of gas from the D6 block.
The brothers have long squabbled over their father's sprawling industrial empire, which was divided between them after he passed away six years ago.
Prasad said Sunday he hopes India's courts - which are notoriously slow - will make a ruling soon.
"We believe the court will make a decision in the near future. Someone will have to make a decision about whether we continue to transfer $20 billion of wealth a year," he said.
The Bombay High Court next meets Sept. 29 to consider the case.
That sludge, Ambani says, is India's ticket to energy independence and Reliance's entry into the club of global energy majors.
"This accomplishment marks a strategic and emotional inflection point for every Indian. It proves that we can disprove the naysayers of the world, who had written off India's ability to produce its own oil and gas," he said Sunday.
Reliance has started production as global oil majors are facing diminishing new discoveries.
Pulling oil from 2,400 metres beneath the cyclone-prone, choppy waters of the Bay of Bengal is a technological feat, the sort of high-tech, high-cost deep-water drilling that was once the province of just a few of the world's top oil companies.
It also comes at a propitious time for India, the world's fifth-largest energy consumer. The country imports about three quarters of its oil and has been staggering under growing oil and gas import costs and an onerous oil subsidy bill.
Within 18 months, oil and gas production from block D6 of the Krishna Godavari basin will increase India's domestic production by 40 per cent, potentially shaving about $20 billion US from the nation's $77 billion oil import bill, according to Reliance officials.
The company says the 7,650 square-kilometre block holds 2.5 billion barrels of oil equivalent, 80 per cent to 85 per cent of it natural gas.
Canada's Niko Resources Ltd. (TSX:NKO), which has a 10 per cent stake in the project, and Reliance, India's largest company by market capitalization, have invested $8.7 billion in developing the block.
India still ranks low on the list of oil-producing countries, and the find is unlikely to put a big dent in global demand for oil, which the International Energy Agency pegs at 86.8 million barrels per day.
But Reliance insists this is just the beginning. "India is not short of hydrocarbons. It just hasn't been explored well," P.M.S. Prasad, president of Reliance's oil and gas division, said Sunday.
Reliance controls 40 exploration blocks in India, including several more in the Krishna Godavari basin.
Ambani called the start of production a "major victory" for India in its battle for energy security. "We can now confidently look forward to production from a series of other fields," he said.
First, however, Reliance must resolve a very Indian problem: An increasingly high-profile fraternal dispute which pits Mukesh Ambani against his younger brother Anil, who has sued Reliance Industries over the gas deposits.
Until that litigation is resolved, Reliance Industries, which expects to start natural gas production in January, can't sell a cubic metre of gas from the D6 block.
The brothers have long squabbled over their father's sprawling industrial empire, which was divided between them after he passed away six years ago.
Prasad said Sunday he hopes India's courts - which are notoriously slow - will make a ruling soon.
"We believe the court will make a decision in the near future. Someone will have to make a decision about whether we continue to transfer $20 billion of wealth a year," he said.
The Bombay High Court next meets Sept. 29 to consider the case.
Sunday, September 21, 2008
Massachusetts Natural Gas
QUINCY —
As Massachusetts lawmakers and environmental groups gear up to block oil drilling off the New England coast, the debate on how much oil and natural gas is out there is back for the first time in close to 30 years.
There may not be lot of oil, but the petroleum industry says there might be enough natural gas there to heat all of the homes in Massachusetts for close to two decades.
But the best answer, according to several sources, is that without new testing, it’s really anyone’s guess how much oil and gas are there.
“It’s like looking at a row of trucks. You assume inside all of them are 100 boxes, but unless you actually go in and count, you have no idea,” said Blossom Robinson, spokeswoman for the U.S. Minerals Management Service.
And no one has counted or measured anything except fish on Georges Bank since 1982, when a federal ban on offshore drilling began.
President Bush decided this summer to end that moratorium; it is set to expire Sept. 30.
As Massachusetts lawmakers and environmental groups gear up to block oil drilling off the New England coast, the debate on how much oil and natural gas is out there is back for the first time in close to 30 years.
There may not be lot of oil, but the petroleum industry says there might be enough natural gas there to heat all of the homes in Massachusetts for close to two decades.
But the best answer, according to several sources, is that without new testing, it’s really anyone’s guess how much oil and gas are there.
“It’s like looking at a row of trucks. You assume inside all of them are 100 boxes, but unless you actually go in and count, you have no idea,” said Blossom Robinson, spokeswoman for the U.S. Minerals Management Service.
And no one has counted or measured anything except fish on Georges Bank since 1982, when a federal ban on offshore drilling began.
President Bush decided this summer to end that moratorium; it is set to expire Sept. 30.
Saturday, September 20, 2008
Liquid Natural Gas Proposed from British Columbia to Asia
Gordon Hamilton, Vancouver Sun
Published: Friday, September 19, 2008
British Columbia's expanding natural gas supplies, coupled with growing demand for gas in Asia, prompted Kitimat LNG to announce Friday it plans to build a liquid natural gas export terminal at Kitimat, dropping previous plans for an import terminal.
The global natural gas market has changed fundamentally, the Calgary-based company said in announcing its reversal. The export proposal is now more viable than importing liquid natural gas.
"Kitimat continues to be a viable and advantageous location to build a West Coast LNG terminal," Rosemary Boulton, president of Kitimat LNG, said in a news release. "The growing economies of the Pacific Rim and rapidly increasing demand for LNG make Asia a natural market for B.C.'s plentiful and expanding supplies of natural gas.
"Kitimat is close to Asian markets and an extensive pipeline network already connects B.C. gas suppliers to the Kitimat area."
The import proposal has already received all regulatory, environmental and government approvals, the company said, adding there are no additional environmental impacts associated with building a liquefaction terminal rather than a regasification terminal.
The proposed plant will cool natural gas to -160 degrees Celsius so it can be transported by ship to Asian markets.
LNG terminals are controversial. A plan by another Calgary company, WestPac LNG Corp., for a liquid natural gas plant on Texada Island has run into opposition from community and environmental groups who do not want LNG being shipped through Georgia Strait.
Kitimat LNG is one of four pipeline and port expansion projects that have been announced for the north by gas and pipeline companies.
The Kitimat proposal has the support of the Prince Rupert and Kitimat mayors as well as the chief of the Haisla First Nation.
Published: Friday, September 19, 2008
British Columbia's expanding natural gas supplies, coupled with growing demand for gas in Asia, prompted Kitimat LNG to announce Friday it plans to build a liquid natural gas export terminal at Kitimat, dropping previous plans for an import terminal.
The global natural gas market has changed fundamentally, the Calgary-based company said in announcing its reversal. The export proposal is now more viable than importing liquid natural gas.
"Kitimat continues to be a viable and advantageous location to build a West Coast LNG terminal," Rosemary Boulton, president of Kitimat LNG, said in a news release. "The growing economies of the Pacific Rim and rapidly increasing demand for LNG make Asia a natural market for B.C.'s plentiful and expanding supplies of natural gas.
"Kitimat is close to Asian markets and an extensive pipeline network already connects B.C. gas suppliers to the Kitimat area."
The import proposal has already received all regulatory, environmental and government approvals, the company said, adding there are no additional environmental impacts associated with building a liquefaction terminal rather than a regasification terminal.
The proposed plant will cool natural gas to -160 degrees Celsius so it can be transported by ship to Asian markets.
LNG terminals are controversial. A plan by another Calgary company, WestPac LNG Corp., for a liquid natural gas plant on Texada Island has run into opposition from community and environmental groups who do not want LNG being shipped through Georgia Strait.
Kitimat LNG is one of four pipeline and port expansion projects that have been announced for the north by gas and pipeline companies.
The Kitimat proposal has the support of the Prince Rupert and Kitimat mayors as well as the chief of the Haisla First Nation.
Friday, September 19, 2008
Liquid Natural Gas Terminal Approved in Oregon!!!
A look at the Bradwood Landing liquefied natural gas terminal planned for the Columbia River.
What's the project
Bradwood Landing, one of three proposals to build liquefied natural gas terminals in the state, would import massive quantities of natural gas to Oregon and neighboring states from producers in the Middle East, Australia or Russia. The terminal's capacity is far greater than the daily consumption of natural gas in Oregon.
Bradwood would offload natural gas supercooled to a condensed liquid from tankers, rewarm it to a gas, and distribute it regionally in pipelines. Bradwood's pipeline would run 36 miles between the terminal, 20 miles east of Astoria on the Columbia River, to an interstate gas hub near Kelso, Wash.
Though not included in Thursday's federal approval of the Bradwood proposal, Northwest Natural Gas Co. and TransCanada Corp. have proposed building another 212-mile pipeline that would carry gas from the terminal to a gas hub in the Willamette Valley, then on to an interstate pipeline in central Oregon to serve California.
The case for LNG
Prominent backers of the Bradwood project include its would-be owner, Houston-based NorthernStar Natural Gas Inc., as well as the state's largest gas utility, NW Natural, which hopes to profit from pipelines and gas-storage facilities serving Bradwood. Industrial gas users and other utilities also have weighed in to support the project.
Backers point to the fact that regional demand for natural gas is rising as the region's population has grown, demand for natural gas to generate electricity has increased, and coal and nuclear plants have become environmentally and politically unacceptable options. They also say supplies from Canada and elsewhere are getting tighter.
LNG, the two companies say, would diversify the state's energy supply, helping cushion future price increases as domestic and Canadian gas supplies shrink.
The case against LNG
Many experts, including the Oregon Department of Energy, believe domestic supplies of natural gas will be more than enough for the foreseeable future. U.S. gas production is expanding, especially as energy producers use new drilling techniques to suck gas from shale formations. By some industry estimates, the U.S. has enough natural gas to last into the next century at current consumption rates.
Demand for LNG is growing overseas, and LNG cargoes bound to Asia are fetching twice the price that domestic gas sells for in the United States. Shipments to the U.S., meanwhile, have dried up because natural gas is so much cheaper here.
LNG terminals and their pipelines, opponents contend, will seriously harm rivers, forests and farmland.
What happened Thursday
After a three-year review, the Federal Energy Regulatory Commission approved the terminal and the Bradwood pipeline in a 4-1 vote, subject to 109 conditions dealing primarily with public-safety and environmental concerns.
The agency found that the LNG terminal and Bradwood pipeline met its safety standards and would do only limited harm to the environment. FERC Chairman Joseph Kelliher said the project is needed to meet the Northwest's rising energy demand. Kelliher also noted that there had been no rush to judgment as critics contend.
The sole dissenter in the FERC vote was Commissioner Jon Wellinghoff, an energy lawyer who was formerly a consumer advocate for utility customers in Nevada. Wellinghoff visited Oregon last year to explain FERC's regulatory process. During his visit, citizens along the proposed pipeline route, environmental groups and property-rights advocates bombarded him with complaints about the process.
In an eight-page dissent Thursday, Wellinghoff concluded that reasonable alternatives were available to serve the region's energy needs "in a more efficient, more reliable and environmentally preferable manner. For these reasons, I conclude that Bradwood Landing is not in the public interest."
Local action
On Tuesday, residents of Clatsop County -- home to two of the three proposed LNG terminals in Oregon -- voted overwhelmingly to ban gas pipelines on land zoned for parks, recreation or open space. Nearly a mile of a pipeline serving Bradwood would run through such land.
Almost 60 percent of the county's 21,051 registered voters returned ballots in the one-issue special election. LNG opponents say the outcome -- 67 percent voted against allowing pipelines to cross the land in question -- sent a clear message to politicians around the state about the desirability of LNG. They also contend the project can't secure state permits if it doesn't meet county land-use laws. Bradwood's backer, Houston-based NorthernStar Natural Gas Inc., claims the vote will have no impact on its permitting process, as the authority for siting natural gas pipelines rests with federal authorities.
Bradwood has become a lightning rod issue in Clatsop County and in communities along proposed pipeline routes. Last spring, the Clatsop County Board of Commissioners approved the project, saying it was compatible with the county's land use laws, despite recommendations from county staff and outside consultants indicating that the project would violate those laws.
Local supporters of the project cite a major increase in property taxes, construction jobs and ongoing employment that Bradwood would bring to the county. Opponents claim the county is going to be left with major new public safety expenses, and that the employment benefits for construction and operation will be small or fleeting.
What's next?
Gov. Ted Kulongoski and advocacy groups have said they would petition for a FERC rehearing. Such a request is due within 30 days, and FERC has another 30 days to respond. FERC then has the option to grant a rehearing, modify its approval to address concerns, or reaffirm the decision.
Many observers think FERC will reaffirm. The agency has already heard objections from many advocacy groups and rejected calls from Oregon's elected leaders for a supplemental environmental review.
Kelliher recently responded to concerns raised by Rep. David Wu, D-Ore., by telling him there had been extensive opportunities for agency and public feedback and an extended public comment period.
"The commission's policy is to ensure that all proposed LNG projects are environmentally sound and consistent with public safety, and then leave it to the market to determine which projects are actually constructed," Kelliher told Wu.
The state's role
Bradwood still needs to obtain permits and certifications from a variety of state agencies. Among them:
The Division of Land Conservation and Development: It must certify that the project complies with both statewide and local land-use and zoning regulations.
The Department of Environmental Quality: It decides whether emissions produced by tankers and Bradwood would meet standards of the federal Environmental Protection Agency and the federal Clean Water Act. The basic question is whether the terminal would do too much harm to water quality through wastewater discharges, dredging, tanker wakes, ballast or cooling water, or silt in a turnaround basin. Several agencies have indicated that the project could put salmon at significant risk.
For now, all of DEQ's permitting is on hold.
The Water Resources Department: It has issued three permits to Bradwood for its use of water for its pipeline, storage tanks and dredging. Permits are still pending for fire protection, industrial use and ballast water.
The Department of State Lands: It would be required to issue a permit so that Bradwood can fill in wetlands and dredge.
Others: The National Marine Fisheries Service and the U.S. Department of Fish and Wildlife must determine that Bradwood would not violate the Endangered Species Act.
By Ted Sickinger
What's the project
Bradwood Landing, one of three proposals to build liquefied natural gas terminals in the state, would import massive quantities of natural gas to Oregon and neighboring states from producers in the Middle East, Australia or Russia. The terminal's capacity is far greater than the daily consumption of natural gas in Oregon.
Bradwood would offload natural gas supercooled to a condensed liquid from tankers, rewarm it to a gas, and distribute it regionally in pipelines. Bradwood's pipeline would run 36 miles between the terminal, 20 miles east of Astoria on the Columbia River, to an interstate gas hub near Kelso, Wash.
Though not included in Thursday's federal approval of the Bradwood proposal, Northwest Natural Gas Co. and TransCanada Corp. have proposed building another 212-mile pipeline that would carry gas from the terminal to a gas hub in the Willamette Valley, then on to an interstate pipeline in central Oregon to serve California.
The case for LNG
Prominent backers of the Bradwood project include its would-be owner, Houston-based NorthernStar Natural Gas Inc., as well as the state's largest gas utility, NW Natural, which hopes to profit from pipelines and gas-storage facilities serving Bradwood. Industrial gas users and other utilities also have weighed in to support the project.
Backers point to the fact that regional demand for natural gas is rising as the region's population has grown, demand for natural gas to generate electricity has increased, and coal and nuclear plants have become environmentally and politically unacceptable options. They also say supplies from Canada and elsewhere are getting tighter.
LNG, the two companies say, would diversify the state's energy supply, helping cushion future price increases as domestic and Canadian gas supplies shrink.
The case against LNG
Many experts, including the Oregon Department of Energy, believe domestic supplies of natural gas will be more than enough for the foreseeable future. U.S. gas production is expanding, especially as energy producers use new drilling techniques to suck gas from shale formations. By some industry estimates, the U.S. has enough natural gas to last into the next century at current consumption rates.
Demand for LNG is growing overseas, and LNG cargoes bound to Asia are fetching twice the price that domestic gas sells for in the United States. Shipments to the U.S., meanwhile, have dried up because natural gas is so much cheaper here.
LNG terminals and their pipelines, opponents contend, will seriously harm rivers, forests and farmland.
What happened Thursday
After a three-year review, the Federal Energy Regulatory Commission approved the terminal and the Bradwood pipeline in a 4-1 vote, subject to 109 conditions dealing primarily with public-safety and environmental concerns.
The agency found that the LNG terminal and Bradwood pipeline met its safety standards and would do only limited harm to the environment. FERC Chairman Joseph Kelliher said the project is needed to meet the Northwest's rising energy demand. Kelliher also noted that there had been no rush to judgment as critics contend.
The sole dissenter in the FERC vote was Commissioner Jon Wellinghoff, an energy lawyer who was formerly a consumer advocate for utility customers in Nevada. Wellinghoff visited Oregon last year to explain FERC's regulatory process. During his visit, citizens along the proposed pipeline route, environmental groups and property-rights advocates bombarded him with complaints about the process.
In an eight-page dissent Thursday, Wellinghoff concluded that reasonable alternatives were available to serve the region's energy needs "in a more efficient, more reliable and environmentally preferable manner. For these reasons, I conclude that Bradwood Landing is not in the public interest."
Local action
On Tuesday, residents of Clatsop County -- home to two of the three proposed LNG terminals in Oregon -- voted overwhelmingly to ban gas pipelines on land zoned for parks, recreation or open space. Nearly a mile of a pipeline serving Bradwood would run through such land.
Almost 60 percent of the county's 21,051 registered voters returned ballots in the one-issue special election. LNG opponents say the outcome -- 67 percent voted against allowing pipelines to cross the land in question -- sent a clear message to politicians around the state about the desirability of LNG. They also contend the project can't secure state permits if it doesn't meet county land-use laws. Bradwood's backer, Houston-based NorthernStar Natural Gas Inc., claims the vote will have no impact on its permitting process, as the authority for siting natural gas pipelines rests with federal authorities.
Bradwood has become a lightning rod issue in Clatsop County and in communities along proposed pipeline routes. Last spring, the Clatsop County Board of Commissioners approved the project, saying it was compatible with the county's land use laws, despite recommendations from county staff and outside consultants indicating that the project would violate those laws.
Local supporters of the project cite a major increase in property taxes, construction jobs and ongoing employment that Bradwood would bring to the county. Opponents claim the county is going to be left with major new public safety expenses, and that the employment benefits for construction and operation will be small or fleeting.
What's next?
Gov. Ted Kulongoski and advocacy groups have said they would petition for a FERC rehearing. Such a request is due within 30 days, and FERC has another 30 days to respond. FERC then has the option to grant a rehearing, modify its approval to address concerns, or reaffirm the decision.
Many observers think FERC will reaffirm. The agency has already heard objections from many advocacy groups and rejected calls from Oregon's elected leaders for a supplemental environmental review.
Kelliher recently responded to concerns raised by Rep. David Wu, D-Ore., by telling him there had been extensive opportunities for agency and public feedback and an extended public comment period.
"The commission's policy is to ensure that all proposed LNG projects are environmentally sound and consistent with public safety, and then leave it to the market to determine which projects are actually constructed," Kelliher told Wu.
The state's role
Bradwood still needs to obtain permits and certifications from a variety of state agencies. Among them:
The Division of Land Conservation and Development: It must certify that the project complies with both statewide and local land-use and zoning regulations.
The Department of Environmental Quality: It decides whether emissions produced by tankers and Bradwood would meet standards of the federal Environmental Protection Agency and the federal Clean Water Act. The basic question is whether the terminal would do too much harm to water quality through wastewater discharges, dredging, tanker wakes, ballast or cooling water, or silt in a turnaround basin. Several agencies have indicated that the project could put salmon at significant risk.
For now, all of DEQ's permitting is on hold.
The Water Resources Department: It has issued three permits to Bradwood for its use of water for its pipeline, storage tanks and dredging. Permits are still pending for fire protection, industrial use and ballast water.
The Department of State Lands: It would be required to issue a permit so that Bradwood can fill in wetlands and dredge.
Others: The National Marine Fisheries Service and the U.S. Department of Fish and Wildlife must determine that Bradwood would not violate the Endangered Species Act.
By Ted Sickinger
NYMEX Natural Gas Price hits $7.62/MMBtu
SAN FRANCISCO (MarketWatch) -- Crude-oil futures closed higher for a second day Thursday but remained below the $100-per-barrel level, overshadowed by a bigger-than-expected buildup in U.S. natural-gas supplies that pulled prices for the latter away from what had been a three-week high.
News that the world's biggest central banks injected additional liquidity into the financial system provided support for oil prices, though uncertainty over the impact on energy demand remained.
Crude for October delivery climbed 72 cents to close at $97.88 a barrel on the New York Mercantile Exchange.
It climbed as high as $102.24 earlier in electronic trading on Globex. It was at $98.02 as of 5:15 p.m. EDT on Globex.
Meanwhile, the October contract for natural gas had climbed to a three-week high of $8.32 per million British thermal units on Globex.
But prices fell after the Energy Department reported a 67 billion-cubic-foot increase in natural-gas supplies for the week ended Sept. 12. Analysts at Global Insight had expected a buildup of 50 billion cubic feet for gas in storage.
October natural gas dropped 28.9 cents, or 3.7%, to finish at $7.621. Earlier, it climbed as high as $8.32 on Globex, its strongest intraday level since Aug. 28.
The rise in last week's natural-gas supplies "was well above expectations, which is somewhat surprising given the fact that quite a bit of Gulf production was still offline in the aftermath of [Hurricane] Gustav," said Beth Sewell, managing partner at Quantum Gas & Power Services.
The supply report issued next week will show results from Hurricane Ike, she noted.
Total stocks of natural gas now stand at 2.972 trillion cubic feet, the Energy Department estimated. This was down 142 billion cubic feet from the year-ago level but 61 billion cubic feet above the five-year average for gas in storage, the data showed.
Money vs. supply and demand
Meanwhile, there were quite a few factors to support the price of oil.
"We're seeing two dynamics playing in the oil market currently: the financial turmoil and supply/demand issues," said Thomas Hartmann, analyst at Altavest Worldwide Trading. "Both are reasonably bullish."
"The financial turmoil is causing much angst in traders and could lead to a loss of confidence in the dollar, potentially causing the inflation factor to creep back into play," he said in emailed comments.
At the same time, "supplies of gasoline have been falling materially in the past weeks, not due to high demand but to lack of production with refinery rates hovering just about 78% of capacity," he said.
On Nymex, October reformulated gasoline climbed by 1.9 cents to close at $2.4824 a gallon while October heating oil lost 4.2 cents to close at $2.7824 a gallon.
News that the world's biggest central banks injected additional liquidity into the financial system provided support for oil prices, though uncertainty over the impact on energy demand remained.
Crude for October delivery climbed 72 cents to close at $97.88 a barrel on the New York Mercantile Exchange.
It climbed as high as $102.24 earlier in electronic trading on Globex. It was at $98.02 as of 5:15 p.m. EDT on Globex.
Meanwhile, the October contract for natural gas had climbed to a three-week high of $8.32 per million British thermal units on Globex.
But prices fell after the Energy Department reported a 67 billion-cubic-foot increase in natural-gas supplies for the week ended Sept. 12. Analysts at Global Insight had expected a buildup of 50 billion cubic feet for gas in storage.
October natural gas dropped 28.9 cents, or 3.7%, to finish at $7.621. Earlier, it climbed as high as $8.32 on Globex, its strongest intraday level since Aug. 28.
The rise in last week's natural-gas supplies "was well above expectations, which is somewhat surprising given the fact that quite a bit of Gulf production was still offline in the aftermath of [Hurricane] Gustav," said Beth Sewell, managing partner at Quantum Gas & Power Services.
The supply report issued next week will show results from Hurricane Ike, she noted.
Total stocks of natural gas now stand at 2.972 trillion cubic feet, the Energy Department estimated. This was down 142 billion cubic feet from the year-ago level but 61 billion cubic feet above the five-year average for gas in storage, the data showed.
Money vs. supply and demand
Meanwhile, there were quite a few factors to support the price of oil.
"We're seeing two dynamics playing in the oil market currently: the financial turmoil and supply/demand issues," said Thomas Hartmann, analyst at Altavest Worldwide Trading. "Both are reasonably bullish."
"The financial turmoil is causing much angst in traders and could lead to a loss of confidence in the dollar, potentially causing the inflation factor to creep back into play," he said in emailed comments.
At the same time, "supplies of gasoline have been falling materially in the past weeks, not due to high demand but to lack of production with refinery rates hovering just about 78% of capacity," he said.
On Nymex, October reformulated gasoline climbed by 1.9 cents to close at $2.4824 a gallon while October heating oil lost 4.2 cents to close at $2.7824 a gallon.
Thursday, September 18, 2008
Frac Drilling Opening Hugh Shale Basins of Natural Gas
After decades of declining US natural-gas production, an advanced drilling system so powerful it fractures rock with high-pressure fluid is opening up vast shale-gas deposits.
Instead of falling, US gas production is rising, with up to 118 years’ worth of “unconventional” natural gas reserves in 21 huge shale basins, an industry study in July reported. Such reserves could make the nation more energy self-sufficient and provide more of a cleaner “bridge fuel” to help meet carbon-reduction goals urged by environmentalists.
Shale gas reserves have a powerful economic lure. Companies, states, and landowners could all reap a windfall in the tens of billions. Some also predict lower heating costs for residential gas users as production increases.
Now, scores of natural gas companies are fanning out from Fort Worth, Texas, where hydraulic fracturing of shale has been done for at least five years, to lease shale lands in 19 states, including Pennsylvania and New York.
But some warn that by expanding “hydraulic fracturing” of shale, America strikes a Faustian bargain: It gains new energy reserves, but it consumes and quite possibly pollutes critical water resources.
“People need to understand that these are not your old-fashioned gas wells,” says Tracy Carluccio, special projects director for Delaware Riverkeeper, a watchdog group worried about a surge in new gas drilling from New York to Pennsylvania and from Ohio to West Virginia. “This technology produces tremendous amounts of polluted water and uses dangerous chemicals in every single well that’s developed.”
Traditional gas wells bore straight into porous stone, using a few thousand gallons of water during drilling. But dense shale has gas locked inside.
Hydraulic fracturing, or “fracking,” and horizontal drilling unlock it.
Each hydraulically fractured horizontal well can require from 2 million to 7 million gallons of fresh water mixed with sand and thousands of gallons of industrial chemicals to make the water penetrate more easily.
This frac-water mixture is blasted at high pressure into shale deposits up to 10,000 feet deep, fracturing them. The sand lodges in the cracks, propping them open and providing a path for the gas to exit after external pressure is released.
Besides using vast amounts of groundwater, scientists and environmentalists worry that toxic frac water – 30 percent or more – remains underground and may years later pollute freshwater aquifers.
Millions of gallons of frac water come back to the surface. It could be treated, but in Texas it is most often reinjected into the ground.
Millions more gallons of “produced” water flow out later during gas production. This flow, too, is often tainted with radioactivity and poisons from the shale. Often stored in pits, that waste can leak or overflow while awaiting reinjection.
Simply put: “Each of these wells uses millions of gallons of fresh water, and all of it is going to be contaminated,” Ms. Carluccio says.
Industry spokesmen say such fears are overblown.
“The wells we drill … are insulated with concrete,” says Chip Minty, a spokesman for Devon Energy, an Oklahoma City-based gas company that pioneered hydraulic fracturing in the Barnett shale formation beneath Fort Worth, Texas. “The purpose is to protect any kind of aquifer or ground water layer. Those processes are controlled by regulatory agencies, and that keeps us safe from any kind of aquifer pollution.”
A pioneer in “best practices,” Devon has also developed a way to purify and reuse frac water. But those techniques are costly and not widely used at present. Whether such practices will be required elsewhere is an open question.
Targets for this new kind of drilling
One huge target is the Marcellus shale basin that spans large parts of New York, Pennsylvania, Ohio, and West Virginia. States are eager to get to get new revenues – and so are many landowners lining up to sign leases.
“I’ll be glad to welcome the crews with open arms,” writes Al Czervic in the Catskill Commentator, an online publication. “Drill here, my friends,” he writes, “Drill here. And then, drill some more.”
But amid this gold-rush-type fever in the Delaware and Susquehanna River Basins, voices warn that environmental safeguards and industry standards need to be beefed up before drill bits hit – or the great gas boom could exact a steep price in polluted water.
“Decades ago, we weren’t careful with coal mining,” wrote Bryan Swistock, a water resources specialist with the Penn State Cooperative Extension, in a recent statement. “As a result, we are still paying huge sums to clean up acid mine drainage. We need to be careful and vigilant or we could see lasting damage to our water resources from so many deep gas wells.”
State environmental agencies and industry experts say multiple systems will be in place to safeguard water.
“The current balanced management approach works – allowing for effective state regulatory programs that appropriately protect the environment while providing for the essential development of oil and gas,” wrote Stephanie Meadows, a senior policy adviser at the American Petroleum Institute, a Washington trade group, in an e-mail response to Monitor questions on hydraulic fracturing.
Where safeguards failed
Still, one can point to examples where those safeguards did not work. New Mexico and Colorado, which have struggled with leakage from frac-water waste pits involving gas exploration, are now moving forward with legislation.
“There are numerous instances in various states of surface water and drinking water contamination from hydraulic fracturing,” says Kate Sinding, a senior attorney with the Natural Resources Defense Council in New York. “Nobody, including the industry, has done any in-depth examination to find out the impact on ground water. We are seeing some bad stuff coming out of individual wells and taps.”
The nation’s shale-gas guinea pigs reside in 15 counties around Fort Worth, where shale-gas extraction using hydraulic fracturing has been validated in recent years. The results have brought wealth to some, but infuriated others.
Charlotte Harris and her husband signed a mineral lease last year. But she’s upset now. She sharply recalls a day last November when her drinking-water well died and a new gas well 100 yards from her Grandview, Texas, home was born.
She washed dishes that morning as usual, she says in an phone interview. But after a shower, her skin itched terribly and she realized the water had a sulfurous odor. Later that day, without warning, her toilet erupted. Water shot out of it “like Niagara Falls.”
About that time, she learned, powerful pump trucks at the nearby well site were sending pulses of water mixed with sand and chemicals thousands of feet down into solid shale to fracture it to increase the flow of gas. She and her husband now believe some of that fluid escaped under pressure much nearer the surface.
After the Harrises complained, the drilling company had the water tested but found no problem. Harris’s next-door neighbor, John Sayers, had a lab test his well water. The lab found toluene, a chemical used in explosives, paint stripper – and often in drilling fluids.
Almost a year later, the Harris family well water, once clear and sweet, is murky and foul-smelling. Ms. Harris’s husband, Stevan, trucks in about 1,500 gallons twice a week, at 15 cents a gallon.
“We’re not using that [well] water for anything at all,” Mr. Sayers says. “I was told not to drink, wash, or anything. Not even water my grass with it.”
Is New York City drinking water at risk?
In July, New York’s governor signed a bill to permit shale-gas drilling using fracturing technology, which could bring the state $1 billion in annual revenues. But the state is first requiring an updated environmental assessment and may yet require companies to reveal the type of chemicals they mix with the water they shoot down the wells – something that Texas does not require.
New York City is one of only four large cities in the nation with unfiltered drinking water. It flows from the northern Catskill region. That’s the same basin in which gas companies want to drill.
Drilling “is completely and utterly inconsistent with a drinking water supply,” said New York City Councilman James Gennaro at a press conference last month. “This would destroy the New York City watershed, and for what? For short-term gains on natural gas.”
But while New York has a drilling freeze pending its environmental review, a gas-drilling rush is on in Pennsylvania’s Susquehanna River region. Scores of wells are being drilled, with applications pending to drill hundreds more. In the long run, some say there may be 10,000 new gas wells across the region.
“We’re hearing various stories … about flow backwater,” says Susan Obleski, a spokeswoman for the Susquehanna River Basin Commission, which oversees water usage. “We could eventually be seeing 29 million gallons a day usage by this industry. That sounds like a lot, but golf courses use double that.”
The concern, however, is that the most productive gas drilling areas tend to be in remote, forested areas, with forested streams – headwaters areas. If water is removed in significant amounts from there, it could damage ecosystems and Susquehanna watershed water quality.
The SBRC has issued two cease-and-desist orders to companies illegally removing water. It has told 23 others to clarify requirements, and found that about 50, in all, are vying for water, leases, and drilling permits in the region.
Tiny Nockamixon Township, which has resisted gas drilling, is being sued by natural-gas drillers. The Pennsylvania Supreme Court has agreed to hear a case in which some towns are seeking to overturn lower court decisions that keep municipalities from having laws regulating gas drilling inside their borders.
Back in Texas, some are fighting the practice of reinjecting frac water into the earth. In Erath County, near Fort Worth, Bill Gordon has successfully protested several new commercial injection wells that, according to him, would have pumped as much as 30,000 barrels a day of untreated frac water underground.
A recent lightning strike set one such well on fire, proving to Mr. Gordon that volatile chemicals remain in the fluid.
“Nobody knows what’s in this drilling fluid,” he says. “I think we need to know.”
What’s being injected deep underground?
Hydraulic fracturing and horizontal drilling are not new. Both date back decades. But their combined use to get gas from shale formations is new within the past decade.
Hydraulic fracturing has long been used to get gas from coal beds, a process some say is similar to shale-gas fracturing.
An Environmental Protection Agency study in 2004 concluded that hydraulic fracturing to get methane gas from coal beds “poses little or no threat” to drinking water supplies. But several EPA scientists have challenged that finding.
“EPA produced a final report … that I believe is scientifically unsound and contrary to the purposes of law,” Weston Wilson, a 30-year EPA veteran, wrote in a whistle-blower petition in 2004. “Based on the available science and literature, EPA’s conclusions are unsupportable.”
Today, chemicals used in fracturing are considered by the companies to be trade secrets. The Energy Policy Act of 2005 exempts companies from being forced by the Clean Water Act, Safe Drinking Water Act, and other federal laws to reveal what chemicals are in their fracturing fluids.
But some say that it’s critical to know what’s being injected deep underground.
“We’re very concerned about this toxic drilling and hydraulic fracturing,” says Gwen Lachelt, director of the Oil and Gas Accountability Project in Durango, Colo. “We need to know what’s in what they’re putting into the ground.”
Instead of falling, US gas production is rising, with up to 118 years’ worth of “unconventional” natural gas reserves in 21 huge shale basins, an industry study in July reported. Such reserves could make the nation more energy self-sufficient and provide more of a cleaner “bridge fuel” to help meet carbon-reduction goals urged by environmentalists.
Shale gas reserves have a powerful economic lure. Companies, states, and landowners could all reap a windfall in the tens of billions. Some also predict lower heating costs for residential gas users as production increases.
Now, scores of natural gas companies are fanning out from Fort Worth, Texas, where hydraulic fracturing of shale has been done for at least five years, to lease shale lands in 19 states, including Pennsylvania and New York.
But some warn that by expanding “hydraulic fracturing” of shale, America strikes a Faustian bargain: It gains new energy reserves, but it consumes and quite possibly pollutes critical water resources.
“People need to understand that these are not your old-fashioned gas wells,” says Tracy Carluccio, special projects director for Delaware Riverkeeper, a watchdog group worried about a surge in new gas drilling from New York to Pennsylvania and from Ohio to West Virginia. “This technology produces tremendous amounts of polluted water and uses dangerous chemicals in every single well that’s developed.”
Traditional gas wells bore straight into porous stone, using a few thousand gallons of water during drilling. But dense shale has gas locked inside.
Hydraulic fracturing, or “fracking,” and horizontal drilling unlock it.
Each hydraulically fractured horizontal well can require from 2 million to 7 million gallons of fresh water mixed with sand and thousands of gallons of industrial chemicals to make the water penetrate more easily.
This frac-water mixture is blasted at high pressure into shale deposits up to 10,000 feet deep, fracturing them. The sand lodges in the cracks, propping them open and providing a path for the gas to exit after external pressure is released.
Besides using vast amounts of groundwater, scientists and environmentalists worry that toxic frac water – 30 percent or more – remains underground and may years later pollute freshwater aquifers.
Millions of gallons of frac water come back to the surface. It could be treated, but in Texas it is most often reinjected into the ground.
Millions more gallons of “produced” water flow out later during gas production. This flow, too, is often tainted with radioactivity and poisons from the shale. Often stored in pits, that waste can leak or overflow while awaiting reinjection.
Simply put: “Each of these wells uses millions of gallons of fresh water, and all of it is going to be contaminated,” Ms. Carluccio says.
Industry spokesmen say such fears are overblown.
“The wells we drill … are insulated with concrete,” says Chip Minty, a spokesman for Devon Energy, an Oklahoma City-based gas company that pioneered hydraulic fracturing in the Barnett shale formation beneath Fort Worth, Texas. “The purpose is to protect any kind of aquifer or ground water layer. Those processes are controlled by regulatory agencies, and that keeps us safe from any kind of aquifer pollution.”
A pioneer in “best practices,” Devon has also developed a way to purify and reuse frac water. But those techniques are costly and not widely used at present. Whether such practices will be required elsewhere is an open question.
Targets for this new kind of drilling
One huge target is the Marcellus shale basin that spans large parts of New York, Pennsylvania, Ohio, and West Virginia. States are eager to get to get new revenues – and so are many landowners lining up to sign leases.
“I’ll be glad to welcome the crews with open arms,” writes Al Czervic in the Catskill Commentator, an online publication. “Drill here, my friends,” he writes, “Drill here. And then, drill some more.”
But amid this gold-rush-type fever in the Delaware and Susquehanna River Basins, voices warn that environmental safeguards and industry standards need to be beefed up before drill bits hit – or the great gas boom could exact a steep price in polluted water.
“Decades ago, we weren’t careful with coal mining,” wrote Bryan Swistock, a water resources specialist with the Penn State Cooperative Extension, in a recent statement. “As a result, we are still paying huge sums to clean up acid mine drainage. We need to be careful and vigilant or we could see lasting damage to our water resources from so many deep gas wells.”
State environmental agencies and industry experts say multiple systems will be in place to safeguard water.
“The current balanced management approach works – allowing for effective state regulatory programs that appropriately protect the environment while providing for the essential development of oil and gas,” wrote Stephanie Meadows, a senior policy adviser at the American Petroleum Institute, a Washington trade group, in an e-mail response to Monitor questions on hydraulic fracturing.
Where safeguards failed
Still, one can point to examples where those safeguards did not work. New Mexico and Colorado, which have struggled with leakage from frac-water waste pits involving gas exploration, are now moving forward with legislation.
“There are numerous instances in various states of surface water and drinking water contamination from hydraulic fracturing,” says Kate Sinding, a senior attorney with the Natural Resources Defense Council in New York. “Nobody, including the industry, has done any in-depth examination to find out the impact on ground water. We are seeing some bad stuff coming out of individual wells and taps.”
The nation’s shale-gas guinea pigs reside in 15 counties around Fort Worth, where shale-gas extraction using hydraulic fracturing has been validated in recent years. The results have brought wealth to some, but infuriated others.
Charlotte Harris and her husband signed a mineral lease last year. But she’s upset now. She sharply recalls a day last November when her drinking-water well died and a new gas well 100 yards from her Grandview, Texas, home was born.
She washed dishes that morning as usual, she says in an phone interview. But after a shower, her skin itched terribly and she realized the water had a sulfurous odor. Later that day, without warning, her toilet erupted. Water shot out of it “like Niagara Falls.”
About that time, she learned, powerful pump trucks at the nearby well site were sending pulses of water mixed with sand and chemicals thousands of feet down into solid shale to fracture it to increase the flow of gas. She and her husband now believe some of that fluid escaped under pressure much nearer the surface.
After the Harrises complained, the drilling company had the water tested but found no problem. Harris’s next-door neighbor, John Sayers, had a lab test his well water. The lab found toluene, a chemical used in explosives, paint stripper – and often in drilling fluids.
Almost a year later, the Harris family well water, once clear and sweet, is murky and foul-smelling. Ms. Harris’s husband, Stevan, trucks in about 1,500 gallons twice a week, at 15 cents a gallon.
“We’re not using that [well] water for anything at all,” Mr. Sayers says. “I was told not to drink, wash, or anything. Not even water my grass with it.”
Is New York City drinking water at risk?
In July, New York’s governor signed a bill to permit shale-gas drilling using fracturing technology, which could bring the state $1 billion in annual revenues. But the state is first requiring an updated environmental assessment and may yet require companies to reveal the type of chemicals they mix with the water they shoot down the wells – something that Texas does not require.
New York City is one of only four large cities in the nation with unfiltered drinking water. It flows from the northern Catskill region. That’s the same basin in which gas companies want to drill.
Drilling “is completely and utterly inconsistent with a drinking water supply,” said New York City Councilman James Gennaro at a press conference last month. “This would destroy the New York City watershed, and for what? For short-term gains on natural gas.”
But while New York has a drilling freeze pending its environmental review, a gas-drilling rush is on in Pennsylvania’s Susquehanna River region. Scores of wells are being drilled, with applications pending to drill hundreds more. In the long run, some say there may be 10,000 new gas wells across the region.
“We’re hearing various stories … about flow backwater,” says Susan Obleski, a spokeswoman for the Susquehanna River Basin Commission, which oversees water usage. “We could eventually be seeing 29 million gallons a day usage by this industry. That sounds like a lot, but golf courses use double that.”
The concern, however, is that the most productive gas drilling areas tend to be in remote, forested areas, with forested streams – headwaters areas. If water is removed in significant amounts from there, it could damage ecosystems and Susquehanna watershed water quality.
The SBRC has issued two cease-and-desist orders to companies illegally removing water. It has told 23 others to clarify requirements, and found that about 50, in all, are vying for water, leases, and drilling permits in the region.
Tiny Nockamixon Township, which has resisted gas drilling, is being sued by natural-gas drillers. The Pennsylvania Supreme Court has agreed to hear a case in which some towns are seeking to overturn lower court decisions that keep municipalities from having laws regulating gas drilling inside their borders.
Back in Texas, some are fighting the practice of reinjecting frac water into the earth. In Erath County, near Fort Worth, Bill Gordon has successfully protested several new commercial injection wells that, according to him, would have pumped as much as 30,000 barrels a day of untreated frac water underground.
A recent lightning strike set one such well on fire, proving to Mr. Gordon that volatile chemicals remain in the fluid.
“Nobody knows what’s in this drilling fluid,” he says. “I think we need to know.”
What’s being injected deep underground?
Hydraulic fracturing and horizontal drilling are not new. Both date back decades. But their combined use to get gas from shale formations is new within the past decade.
Hydraulic fracturing has long been used to get gas from coal beds, a process some say is similar to shale-gas fracturing.
An Environmental Protection Agency study in 2004 concluded that hydraulic fracturing to get methane gas from coal beds “poses little or no threat” to drinking water supplies. But several EPA scientists have challenged that finding.
“EPA produced a final report … that I believe is scientifically unsound and contrary to the purposes of law,” Weston Wilson, a 30-year EPA veteran, wrote in a whistle-blower petition in 2004. “Based on the available science and literature, EPA’s conclusions are unsupportable.”
Today, chemicals used in fracturing are considered by the companies to be trade secrets. The Energy Policy Act of 2005 exempts companies from being forced by the Clean Water Act, Safe Drinking Water Act, and other federal laws to reveal what chemicals are in their fracturing fluids.
But some say that it’s critical to know what’s being injected deep underground.
“We’re very concerned about this toxic drilling and hydraulic fracturing,” says Gwen Lachelt, director of the Oil and Gas Accountability Project in Durango, Colo. “We need to know what’s in what they’re putting into the ground.”
Wednesday, September 17, 2008
Brazil Hopeful 120 MMCMD Additional
RIO DE JANEIRO, Brazil: A Brazilian energy analyst says recent offshore oil finds may help the country produce 120 million cubic meters of natural gas a day.
Marco Tavares, managing director of Brazil's Gas Energy consulting firm, says that would make Brazil self-sufficient in natural gas.
Brazil consumes about 60 million cubic meters of the fuel daily to power its energy grid, and as fuel for cars and cooking.
About half that comes from Bolivia, where anti-government protests and pipeline sabotage disrupted exports to Brazil last week.
Brazil has been looking for ways to ease its dependence on gas imports.
Tavares spoke Tuesday at an oil and gas forum in Rio de Janeiro. He did not say when Brazil might be able to boost gas production.
Marco Tavares, managing director of Brazil's Gas Energy consulting firm, says that would make Brazil self-sufficient in natural gas.
Brazil consumes about 60 million cubic meters of the fuel daily to power its energy grid, and as fuel for cars and cooking.
About half that comes from Bolivia, where anti-government protests and pipeline sabotage disrupted exports to Brazil last week.
Brazil has been looking for ways to ease its dependence on gas imports.
Tavares spoke Tuesday at an oil and gas forum in Rio de Janeiro. He did not say when Brazil might be able to boost gas production.
Tuesday, September 16, 2008
Natural Gas Prices Holding After the Storm
SAN FRANCISCO (MarketWatch) -- Oil futures closed below $100 per barrel Monday, at their lowest level in seven months as problems in the financial sector fueled concerns over a recession and as assessments of Hurricane Ike showed limited damage to key refineries in the Gulf of Mexico.
But natural-gas prices recovered from a low near the $7-per million British thermal units mark, as most of the energy production in the Gulf remained shut.
"I think oil is caught in a paper bear trap at present, which is continuing to force the price down, despite supply disruptions and general uneasiness in the geopolitical picture," said Neal Ryan, a managing partner at Ryan Oil & Gas Partners.
But "eventually as we head into winter, the lack of oil, gas and natural-gas additions to storage in the last month will show up in higher prices down the road," he said in emailed comments. "This is already being reflected in the bounce back of natural-gas prices."
Crude oil for October delivery fell $5.47, or 5.4%, to close at $95.71 a barrel on the New York Mercantile Exchange.
It dropped to a low of $94.13 earlier Monday in electronic trading on Globex, oil's weakest intraday day level since mid-February. October crude was at $94.95 on Globex as of 3:30 p.m. EDT.
"We are in the midst of a paramount shift in the financial and banking system the likes of which we have never seen," said Zachary Oxman, a senior trader at Wisdom Financial.
"Crude is taking a pounding off of two things: the continued de-leverage of risk and the fear of a demand slowdown for the product as the recession we are in gets deeper and longer," he said in emailed comments.
Hurricane Ike also apparently failed to cause as much damage to energy facilities in the Gulf of Mexico as the energy markets expected.
"It's an expected relief sell-off after refineries saw less damage then expected -- also because the refining slowdown will not require so much crude," said Kevin Kerr, Global Commodities Alert at KerrAlert.com, in emailed comments.
Prices for petroleum products finished lower for now. October reformulated gasoline fell 20.8 cents, or 7.5%, to end at $2.5614 a gallon and October heating oil dropped 14.8 cents, or 5%, to end at $2.7912 a gallon.
Natural-gas prices rebound Despite oil's steep price decline Monday, natural-gas futures managed to bounce off their low.
Natural gas for October delivery closed at $7.374 per million British thermal units on Nymex. That's up a minor 0.1% for the session, but well above the day's intraday low of $7.07.
Support for natural-gas prices "may have something to do with the total loss of 10 or 11 offshore platforms," said Beth Sewell, a managing partner at Quantum Gas & Power Services, citing news reports.
Hurricane Ike destroyed at least 10 offshore oil and gas platforms in the Gulf, the Associated Press reported Monday.
But oil prices likely aren't finding price support based off that news because the market is actually "a lot better off" than in the aftermath of the 2005 hurricanes, said Sewell. A total of 113 platforms were destroyed and 52 suffered significant damage in the wake of hurricanes Katrina and Rita in 2005, according to the U.S. Energy Department.
Just about all of the oil production in the Gulf has been shut-in, as well as about 93.8% of natural-gas production, the U.S. Minerals Management Service said in a report issued Monday.
"Damage to refineries and chemical plants appears to be minimal," said Charles Perry, president of energy-consulting firm Perry Management. "The big problem now is none of the ones in the Houston area have power, and it may be a week or more before they all have power back on -- then allow another week for them to get back to full production."
All of this bodes "very poorly for gasoline supplies but even worse for heating oil," said Kerr. "It is going to be a long, cold and expensive Winter for many Americans."
Still, "refineries, all of which are around Galveston Bay or the Houston ship channel, were spared from all but minor damage by the fact that the eye of the hurricane went up Galveston Bay, and did not push the storm surge into the bay that had been expected," Perry said.
But natural-gas prices recovered from a low near the $7-per million British thermal units mark, as most of the energy production in the Gulf remained shut.
"I think oil is caught in a paper bear trap at present, which is continuing to force the price down, despite supply disruptions and general uneasiness in the geopolitical picture," said Neal Ryan, a managing partner at Ryan Oil & Gas Partners.
But "eventually as we head into winter, the lack of oil, gas and natural-gas additions to storage in the last month will show up in higher prices down the road," he said in emailed comments. "This is already being reflected in the bounce back of natural-gas prices."
Crude oil for October delivery fell $5.47, or 5.4%, to close at $95.71 a barrel on the New York Mercantile Exchange.
It dropped to a low of $94.13 earlier Monday in electronic trading on Globex, oil's weakest intraday day level since mid-February. October crude was at $94.95 on Globex as of 3:30 p.m. EDT.
"We are in the midst of a paramount shift in the financial and banking system the likes of which we have never seen," said Zachary Oxman, a senior trader at Wisdom Financial.
"Crude is taking a pounding off of two things: the continued de-leverage of risk and the fear of a demand slowdown for the product as the recession we are in gets deeper and longer," he said in emailed comments.
Hurricane Ike also apparently failed to cause as much damage to energy facilities in the Gulf of Mexico as the energy markets expected.
"It's an expected relief sell-off after refineries saw less damage then expected -- also because the refining slowdown will not require so much crude," said Kevin Kerr, Global Commodities Alert at KerrAlert.com, in emailed comments.
Prices for petroleum products finished lower for now. October reformulated gasoline fell 20.8 cents, or 7.5%, to end at $2.5614 a gallon and October heating oil dropped 14.8 cents, or 5%, to end at $2.7912 a gallon.
Natural-gas prices rebound Despite oil's steep price decline Monday, natural-gas futures managed to bounce off their low.
Natural gas for October delivery closed at $7.374 per million British thermal units on Nymex. That's up a minor 0.1% for the session, but well above the day's intraday low of $7.07.
Support for natural-gas prices "may have something to do with the total loss of 10 or 11 offshore platforms," said Beth Sewell, a managing partner at Quantum Gas & Power Services, citing news reports.
Hurricane Ike destroyed at least 10 offshore oil and gas platforms in the Gulf, the Associated Press reported Monday.
But oil prices likely aren't finding price support based off that news because the market is actually "a lot better off" than in the aftermath of the 2005 hurricanes, said Sewell. A total of 113 platforms were destroyed and 52 suffered significant damage in the wake of hurricanes Katrina and Rita in 2005, according to the U.S. Energy Department.
Just about all of the oil production in the Gulf has been shut-in, as well as about 93.8% of natural-gas production, the U.S. Minerals Management Service said in a report issued Monday.
"Damage to refineries and chemical plants appears to be minimal," said Charles Perry, president of energy-consulting firm Perry Management. "The big problem now is none of the ones in the Houston area have power, and it may be a week or more before they all have power back on -- then allow another week for them to get back to full production."
All of this bodes "very poorly for gasoline supplies but even worse for heating oil," said Kerr. "It is going to be a long, cold and expensive Winter for many Americans."
Still, "refineries, all of which are around Galveston Bay or the Houston ship channel, were spared from all but minor damage by the fact that the eye of the hurricane went up Galveston Bay, and did not push the storm surge into the bay that had been expected," Perry said.
Monday, September 15, 2008
Bangladesh Natural Gas Needs are 20000 MMCFD
Bangladesh has a perspective plan to supply power to its entire citizen by 2020. It is one of fundamental requirement for maintaining its current GDP growth rate of about 6% and also to achieve its Millennium Development Goal. Considering the situation with three quarter of 2008 almost gone serious apprehension now being made whether the 2020 vision and MDG of Bangladesh can be at all achieved. People do not have much faith in Bangladesh government statistical figures. But the conservatives feel that about 35% of Bangladeshi population have access to some form of energy now. But energy supply in most cases is not reliable and dependable unfortunately. So given the present scenario even the most optimistic person would hesitate to believe that achieving power for all by 2020 is at all possible.
Bangladesh is currently having serious energy crisis .It can supply about 3500 MW power per ay against a national demand of 5200MW. Production and supply of natural gas which is the major source of power generation is also in crisis. National demand is now about 2000 MMCFD but production capacity is about 1830 MMCFD and transmission capacity is 1750 MMCFD.
Energy crisis is causing serious problem in industrial growth, trade, commerce and civic life. A country having all the potential to grow into mid income group utilizing all its resources in the most economic way must set out its priorities and pursue vigorously its implementation. This write up will discuss the present situation, future possibilities and will try to identify the priorities.
Bangladesh as we all know is one of the world’s poorest and most densely populated countries. It is also highly vulnerable to natural disasters such as cyclones, flooding and drought. Every year massive flood inundates most of its land, destroy standing crops. Occasional cyclone and tidal bore s also create miseries. Even then its struggling masses, brave framers could make the country turn around .But there is another human factor which bogs down its development efforts. Civil unrest, political instability and widespread corruption make it a very unsuitable place for required foreign investment.
Natural gas is the major source of commercial energy, and accounts for almost 75% of commercial energy consumption. The largest gas consumers are the power and fertiliser industries, which account for around 70% of daily production. Current supply capacity of 1,750 MMcf/d, however, is believed to be about 200 MMcf/d short to meet the demand. Virtually less than adequate exploration and very little development of known resource over the last ten years have the situation to the present crisis. The demand however increased at a rate of 10% per annum. Gas supply to a major growth centre Chittagong region in particular and rest of the country in general has entered red zone. No new bulk consumer can get gas connection. Supply to existing consumers is interrupted every now and then. About 500MW available capacity of power per day can not be generated for lack of require gas supply, fertilizer production is also seriously affected. There may be serious deficit of electricity, fertilizer for farmers in the ensuing Aman cultivation compounding the miseries. Many export oriented industry all over the country are complain about lack of energy for keeping their factories running and as such failing in the export commitment.
Bangladesh is currently having serious energy crisis .It can supply about 3500 MW power per ay against a national demand of 5200MW. Production and supply of natural gas which is the major source of power generation is also in crisis. National demand is now about 2000 MMCFD but production capacity is about 1830 MMCFD and transmission capacity is 1750 MMCFD.
Energy crisis is causing serious problem in industrial growth, trade, commerce and civic life. A country having all the potential to grow into mid income group utilizing all its resources in the most economic way must set out its priorities and pursue vigorously its implementation. This write up will discuss the present situation, future possibilities and will try to identify the priorities.
Bangladesh as we all know is one of the world’s poorest and most densely populated countries. It is also highly vulnerable to natural disasters such as cyclones, flooding and drought. Every year massive flood inundates most of its land, destroy standing crops. Occasional cyclone and tidal bore s also create miseries. Even then its struggling masses, brave framers could make the country turn around .But there is another human factor which bogs down its development efforts. Civil unrest, political instability and widespread corruption make it a very unsuitable place for required foreign investment.
Natural gas is the major source of commercial energy, and accounts for almost 75% of commercial energy consumption. The largest gas consumers are the power and fertiliser industries, which account for around 70% of daily production. Current supply capacity of 1,750 MMcf/d, however, is believed to be about 200 MMcf/d short to meet the demand. Virtually less than adequate exploration and very little development of known resource over the last ten years have the situation to the present crisis. The demand however increased at a rate of 10% per annum. Gas supply to a major growth centre Chittagong region in particular and rest of the country in general has entered red zone. No new bulk consumer can get gas connection. Supply to existing consumers is interrupted every now and then. About 500MW available capacity of power per day can not be generated for lack of require gas supply, fertilizer production is also seriously affected. There may be serious deficit of electricity, fertilizer for farmers in the ensuing Aman cultivation compounding the miseries. Many export oriented industry all over the country are complain about lack of energy for keeping their factories running and as such failing in the export commitment.
Sunday, September 14, 2008
Bolivia Protests - Brazil Short Natural Gas
Brazil yesterday faced severe shortages of natural gas after violent protests in Bolivia caused the temporary closure of a pipeline that supplies about a quarter of Brazil's daily needs.
At least three people died in Bolivia during yesterday's violent clashes between pro- and anti-government demonstrators.
Residents of the more developed eastern lowlands have been demanding autonomy from the government in La Paz in protests that have escalated since last year.
President Evo Morales accused the US of supporting the anti-government demonstrators and on Wednesday expelled Philip Goldberg, the US ambassador. Mr Morales said Mr Goldberg had conspired with demonstrators in what a Bolivian government spokesman called "an attempt to spark a civil war".
The US state department last night declared Gustavo Guzman, Bolivian ambassador to Washington, persona non grata.
The department earlier said Bolivia's accusations were "baseless" and described the move as "a grave error that has seriously damaged the bilateral relationship".
Luiz Inácio Lula da Silva, Brazil's president, yesterday called on the "group of friends of Bolivia", formed six months ago and consisting of Brazil, Colombia and Argentina, to help bring about a peaceful settlement. He had telephone conversations yesterday with Mr Morales, and presidents Hugo Chávez of Venezuela and Cristina Fernández of Argentina. His office also spoke to Colombia's foreign minister and Mr Lula da Silva was expected to speak to President Michelle Bachelet of Chile last night.
"The president is keen to help bring about a negotiated solution," a presidential spokeswoman said.
Brazil's foreign ministry earlier said the government was following the situation "with grave concern".
Local news agencies reported that, privately, members of the Brazilian government had expressed dissatisfaction at Mr Morales's handling of the crisis.
For nearly three weeks, anti-government protesters have held roadblocks in south-eastern Bolivia near pipelines that carry 30m cubic metres of gas to Brazil each day. An explosion on Wednesday evening damaged one pipeline, reducing supplies by 3m cubic metres a day. Early on Thursday saboteurs damaged a valve on another pipeline carrying 14m cubic metres, although the damage was repaired later in the day according to Transierra, the company that runs the pipeline.
Edson Lobão, Brazil's mines and energy minister, was expected to announce measures yesterday evening to deal with the shortage.
"This is very serious," said Adriano Pires, an oil industry analyst in Rio de Janeiro. "Half the gas we consume comes from Bolivia, and up to 100 per cent in southern Brazil."
He said supply shortages would be felt among residential and industrial users, by drivers of vehicles running on natural gas - many taxis in Brazil use the fuel - and by the ceramics industry, which is dependent on natural gas.
Bolivia has the second largest reserves of natural gas in South America after Venezuela, all located in the insurgent eastern half of the country.
At least three people died in Bolivia during yesterday's violent clashes between pro- and anti-government demonstrators.
Residents of the more developed eastern lowlands have been demanding autonomy from the government in La Paz in protests that have escalated since last year.
President Evo Morales accused the US of supporting the anti-government demonstrators and on Wednesday expelled Philip Goldberg, the US ambassador. Mr Morales said Mr Goldberg had conspired with demonstrators in what a Bolivian government spokesman called "an attempt to spark a civil war".
The US state department last night declared Gustavo Guzman, Bolivian ambassador to Washington, persona non grata.
The department earlier said Bolivia's accusations were "baseless" and described the move as "a grave error that has seriously damaged the bilateral relationship".
Luiz Inácio Lula da Silva, Brazil's president, yesterday called on the "group of friends of Bolivia", formed six months ago and consisting of Brazil, Colombia and Argentina, to help bring about a peaceful settlement. He had telephone conversations yesterday with Mr Morales, and presidents Hugo Chávez of Venezuela and Cristina Fernández of Argentina. His office also spoke to Colombia's foreign minister and Mr Lula da Silva was expected to speak to President Michelle Bachelet of Chile last night.
"The president is keen to help bring about a negotiated solution," a presidential spokeswoman said.
Brazil's foreign ministry earlier said the government was following the situation "with grave concern".
Local news agencies reported that, privately, members of the Brazilian government had expressed dissatisfaction at Mr Morales's handling of the crisis.
For nearly three weeks, anti-government protesters have held roadblocks in south-eastern Bolivia near pipelines that carry 30m cubic metres of gas to Brazil each day. An explosion on Wednesday evening damaged one pipeline, reducing supplies by 3m cubic metres a day. Early on Thursday saboteurs damaged a valve on another pipeline carrying 14m cubic metres, although the damage was repaired later in the day according to Transierra, the company that runs the pipeline.
Edson Lobão, Brazil's mines and energy minister, was expected to announce measures yesterday evening to deal with the shortage.
"This is very serious," said Adriano Pires, an oil industry analyst in Rio de Janeiro. "Half the gas we consume comes from Bolivia, and up to 100 per cent in southern Brazil."
He said supply shortages would be felt among residential and industrial users, by drivers of vehicles running on natural gas - many taxis in Brazil use the fuel - and by the ceramics industry, which is dependent on natural gas.
Bolivia has the second largest reserves of natural gas in South America after Venezuela, all located in the insurgent eastern half of the country.
Saturday, September 13, 2008
Natural Gas Bounces with Hurricane
Natural-gas futures closed nearly 2% higher Friday on concerns that Hurricane Ike may cause damage to refining infrastructure in the Gulf of Mexico region and potentially disrupt energy production for a prolonged period.
Crude prices finished slightly higher, but briefly dipped below $100 a barrel for the first time since early April and suffered a loss of 4.8% for the week. Damage to refineries in the region may reduce demand for oil, analysts said.
"Oil wasn't an issue," said Darin Newsom, DTN senior analyst. "In fact, it could almost be viewed as bearish due to drilling platforms likely being undamaged for the most part, [and] crude-oil stocks could build if refineries are shut down for any length of time."
Natural gas for October delivery tacked on 11.8 cents to close at $7.366 per million British thermal units on the New York Mercantile Exchange. Earlier, it rose as high as $7.67 in electronic trading on Globex, its strongest intraday level in two weeks. But it still lost a total of 1.1% for this week.
Crude prices finished slightly higher, but briefly dipped below $100 a barrel for the first time since early April and suffered a loss of 4.8% for the week. Damage to refineries in the region may reduce demand for oil, analysts said.
"Oil wasn't an issue," said Darin Newsom, DTN senior analyst. "In fact, it could almost be viewed as bearish due to drilling platforms likely being undamaged for the most part, [and] crude-oil stocks could build if refineries are shut down for any length of time."
Natural gas for October delivery tacked on 11.8 cents to close at $7.366 per million British thermal units on the New York Mercantile Exchange. Earlier, it rose as high as $7.67 in electronic trading on Globex, its strongest intraday level in two weeks. But it still lost a total of 1.1% for this week.
Friday, September 12, 2008
Hurricane Ike Affecting Natural Gas Production in the Gulf
By Reg Curren
Sept. 12 (Bloomberg) -- Natural gas futures rose in New York as Hurricane Ike surged through the Gulf of Mexico, shutting most offshore output for a second week.
Ike, a Category 2 storm, forced companies to keep a majority of offshore production shut, after closing platforms for Hurricane Gustav earlier this month. About 14 percent of U.S. natural gas output comes from offshore wells in the Gulf. Utilities and storage companies typically put gas into storage this time of year for use in the winter, when demand peaks.
``This is 100 percent Ike,'' said Peter Linder, an analyst and senior adviser at DeltaOne Energy Fund in Calgary. ``The storm is going to be in the producing area. We should see another bullish storage report next week.''
Natural gas for October delivery rose 28.1 cents, or 3.9 percent, to $7.529 per million British thermal units at 10:13 a.m. on the New York Mercantile Exchange. Prices have climbed 17 percent from a year ago.
Supplies advanced 58 billion cubic feet in the week ended Sept. 5 to 2.905 trillion cubic feet, the U.S. Energy Department reported yesterday. The average stockpile increase for the same week over the past five years is 78 billion cubic feet.
Stockpile gains were hampered by the closing of production last week in the Gulf for Gustav. About 93 percent of the Gulf's daily output of 7.4 billion cubic feet was shut as of yesterday because of Ike. The storm may strike a large portion of the Texas coast, forecasters said today.
Sept. 12 (Bloomberg) -- Natural gas futures rose in New York as Hurricane Ike surged through the Gulf of Mexico, shutting most offshore output for a second week.
Ike, a Category 2 storm, forced companies to keep a majority of offshore production shut, after closing platforms for Hurricane Gustav earlier this month. About 14 percent of U.S. natural gas output comes from offshore wells in the Gulf. Utilities and storage companies typically put gas into storage this time of year for use in the winter, when demand peaks.
``This is 100 percent Ike,'' said Peter Linder, an analyst and senior adviser at DeltaOne Energy Fund in Calgary. ``The storm is going to be in the producing area. We should see another bullish storage report next week.''
Natural gas for October delivery rose 28.1 cents, or 3.9 percent, to $7.529 per million British thermal units at 10:13 a.m. on the New York Mercantile Exchange. Prices have climbed 17 percent from a year ago.
Supplies advanced 58 billion cubic feet in the week ended Sept. 5 to 2.905 trillion cubic feet, the U.S. Energy Department reported yesterday. The average stockpile increase for the same week over the past five years is 78 billion cubic feet.
Stockpile gains were hampered by the closing of production last week in the Gulf for Gustav. About 93 percent of the Gulf's daily output of 7.4 billion cubic feet was shut as of yesterday because of Ike. The storm may strike a large portion of the Texas coast, forecasters said today.
Biofuels Versus Natural Gas - The Billionaires Fight!
Clean technology venture capitalist Vinod Khosla slammed energy magnate T. Boone Pickens’ plan to boost natural gas vehicles to sever America’s dependence on oil as a “dead end,” at an event sponsored by the Silicon Valley Leadership Group Wednesday at Santa Clara University.
Khosla, principal at clean tech venture capital firm Khosla Ventures, said despite emissions reductions of 20 percent compared to gasoline-powered vehicles and that natural gas is available today at relatively low prices, relying on another fossil fuel in vehicles is a flawed model.
“It’s a dead end,” Khosla said. “We shouldn’t do these interim dead-end technologies like natural gas. Let’s not spend public money at low rates of return.”
Khosla also said hydrogen will never be an economically viable alternative to gasoline.
“The technology with the largest carbon reduction possibility is the internal combustion engine powered by biofuels,” Khosla said. “And we should really focus on non-food biofuels and get out of food-based biofuels. It’s much cheaper and much more scalable,” than all other transportation options.
Khosla Ventures has several biofuels investments including those in LS9, Amyris and Mascoma and others.
Khosla, principal at clean tech venture capital firm Khosla Ventures, said despite emissions reductions of 20 percent compared to gasoline-powered vehicles and that natural gas is available today at relatively low prices, relying on another fossil fuel in vehicles is a flawed model.
“It’s a dead end,” Khosla said. “We shouldn’t do these interim dead-end technologies like natural gas. Let’s not spend public money at low rates of return.”
Khosla also said hydrogen will never be an economically viable alternative to gasoline.
“The technology with the largest carbon reduction possibility is the internal combustion engine powered by biofuels,” Khosla said. “And we should really focus on non-food biofuels and get out of food-based biofuels. It’s much cheaper and much more scalable,” than all other transportation options.
Khosla Ventures has several biofuels investments including those in LS9, Amyris and Mascoma and others.
Thursday, September 11, 2008
$2,560 an Acre for Drilling Rights in Pennsylvania
NEW YORK (Associated Press) - Five out-of-state companies were the high bidders on leases that will allow them to drill for natural gas and oil on more than 74,000 acres of publicly owned land in northern Pennsylvania and provide a $190 million shot in the arm for state parks and recreation.
The companies were among seven that bid on the leases of 18 tracts in three state forests that are over the potentially lucrative _ and largely untapped _ natural-gas formation known the Marcellus Shale.
Despite the competitive bidding that opened in July, the first such lease sale in six years, the companies still need permits from the state Department of Environmental Protection and are likely to move more slowly with actual drilling.
"Our expectation would be that we wouldn't see any activity for about two years," spokeswoman Christina Novak of the state Department of Conservation and Natural Resources, which owns and manages 2.1 million acres of state forest land, said Wednesday.
By law, the money will go into the state's Oil and Gas Lease Fund, which is reserved for conservation, recreation, dams and floor control, Novak said. In the past, the money has been used for such purposes as expanding state parks and buying mineral rights on land that the state already owns.
Spurred by high natural-gas prices, companies across North America are jockeying to make deals with the owners of private land atop the Marcellus Shale, a deep gas reservoir that lies 6,000 to 8,000 feet underground.
The best drilling prospects are in upstate New York, eastern Ohio and across much of Pennsylvania and West Virginia. Geologists have known about the gas trapped in the Marcellus Shale for decades, but only recently developed a way to extract it.
The winning bidders on the state forest tracts in Tioga and Lycoming counties included Texas-based ExxonMobil, which submitted high bids for leases on six tracts, and Texas-based Anadarko Exploration & Production Company LP, which won five leases. The others were the New York-based Seneca Energy Production Company, which won four leases; New York-based Fortuna Energy Inc., which won two; and Texas-based Hunt Oil USA Inc., which won one.
The 10-year leases include annual per-acre rental fees starting in the second year _ the sale price counts as the first year's payment _ and a 16 percent state royalty on natural-gas production.
Since 1947, the department has held 72 lease sales and there are currently 650 gas wells in production on 207,000 acres in state forests.
A moratorium on drilling was imposed in 2003 in response to complaints that roads, well pads and pipelines were destroying wildlife habitat, but that was lifted earlier this year at the same time the department announced the lease sale. Top of page
The companies were among seven that bid on the leases of 18 tracts in three state forests that are over the potentially lucrative _ and largely untapped _ natural-gas formation known the Marcellus Shale.
Despite the competitive bidding that opened in July, the first such lease sale in six years, the companies still need permits from the state Department of Environmental Protection and are likely to move more slowly with actual drilling.
"Our expectation would be that we wouldn't see any activity for about two years," spokeswoman Christina Novak of the state Department of Conservation and Natural Resources, which owns and manages 2.1 million acres of state forest land, said Wednesday.
By law, the money will go into the state's Oil and Gas Lease Fund, which is reserved for conservation, recreation, dams and floor control, Novak said. In the past, the money has been used for such purposes as expanding state parks and buying mineral rights on land that the state already owns.
Spurred by high natural-gas prices, companies across North America are jockeying to make deals with the owners of private land atop the Marcellus Shale, a deep gas reservoir that lies 6,000 to 8,000 feet underground.
The best drilling prospects are in upstate New York, eastern Ohio and across much of Pennsylvania and West Virginia. Geologists have known about the gas trapped in the Marcellus Shale for decades, but only recently developed a way to extract it.
The winning bidders on the state forest tracts in Tioga and Lycoming counties included Texas-based ExxonMobil, which submitted high bids for leases on six tracts, and Texas-based Anadarko Exploration & Production Company LP, which won five leases. The others were the New York-based Seneca Energy Production Company, which won four leases; New York-based Fortuna Energy Inc., which won two; and Texas-based Hunt Oil USA Inc., which won one.
The 10-year leases include annual per-acre rental fees starting in the second year _ the sale price counts as the first year's payment _ and a 16 percent state royalty on natural-gas production.
Since 1947, the department has held 72 lease sales and there are currently 650 gas wells in production on 207,000 acres in state forests.
A moratorium on drilling was imposed in 2003 in response to complaints that roads, well pads and pipelines were destroying wildlife habitat, but that was lifted earlier this year at the same time the department announced the lease sale. Top of page
Wednesday, September 10, 2008
City of San Antonio's Natural Gas System
SAN ANTONIO (Reuters) - San Antonio unveiled a deal on Tuesday that will make it the first U.S. city to harvest methane gas from human waste on a commercial scale and turn it into clean-burning fuel.
San Antonio residents produce about 140,000 tons a year of a substance gently referred to as "biosolids," which can be reprocessed into natural gas, said Steve Clouse, chief operating officer of the city's water system.
"You may call it something else," Clouse said, but for area utilities, the main byproduct of human waste - methane gas - will soon be converted into natural gas to burn in their power plants.
The city approved a deal where Massachusetts-based Ameresco Inc will convert the city's biosolids into natural gas, which could generate about 1.5 million cubic feet per day, he said.
Methane gas, which is a byproduct of human and organic waste, is a principal component of the natural gas used to fuel furnaces, power plants, and other combustion-based generators.
"The private vendor will come onto the facility, construct some gas cleaning systems, remove the moisture, remove the carbon dioxide content, and then sell that gas on the open market," Clouse said.
The gas will be sold to power generators, he said.
Some communities are using methane gas harvested from solid waste to power smaller facilities like sewage treatment plants, but San Antonio is the first to see large-scale conversion of methane gas from sewage into fuel for power generation, he said.
Following the agreement, more than 90 percent of materials flushed down the toilets and sinks of San Antonio will be recycled, he said. Liquid is now used for irrigation, many of the solids are made into compost, and now the methane gas will be recycled for power generation.
San Antonio residents produce about 140,000 tons a year of a substance gently referred to as "biosolids," which can be reprocessed into natural gas, said Steve Clouse, chief operating officer of the city's water system.
"You may call it something else," Clouse said, but for area utilities, the main byproduct of human waste - methane gas - will soon be converted into natural gas to burn in their power plants.
The city approved a deal where Massachusetts-based Ameresco Inc will convert the city's biosolids into natural gas, which could generate about 1.5 million cubic feet per day, he said.
Methane gas, which is a byproduct of human and organic waste, is a principal component of the natural gas used to fuel furnaces, power plants, and other combustion-based generators.
"The private vendor will come onto the facility, construct some gas cleaning systems, remove the moisture, remove the carbon dioxide content, and then sell that gas on the open market," Clouse said.
The gas will be sold to power generators, he said.
Some communities are using methane gas harvested from solid waste to power smaller facilities like sewage treatment plants, but San Antonio is the first to see large-scale conversion of methane gas from sewage into fuel for power generation, he said.
Following the agreement, more than 90 percent of materials flushed down the toilets and sinks of San Antonio will be recycled, he said. Liquid is now used for irrigation, many of the solids are made into compost, and now the methane gas will be recycled for power generation.
Tuesday, September 9, 2008
U.S. Presidential Candidates Talking Natural Gas
KANSAS CITY, Mo. — Oilman T. Boone Pickens said he's already accomplished one of his goals in introducing a plan to wean the country off of foreign oil by promoting alternative fuels.
"What I wanted when I started this campaign of mine, what my plan was, was to get it elevated so the candidates were going to talk about it," Pickens said Monday at a meeting of the Society of American Business Editors and Writers Inc.
Pickens said he met with both Republican presidential nominee John McCain and Democratic nominee candidate Barack Obama to discuss his "Pickens Plan" for energy independence, and "both of them were 10s as far as interest."
While McCain focused on nuclear energy and Obama is interested in hybrid cars, it is important that the issue is on the front burner of the presidential campaign, Pickens said.
"I don't even want to talk politics, I don't even want to waste time on anything politically related," he said. "This is totally nonpartisan, this is something both parties can work on together."
Pickens, an 80-year-old who now heads the Dallas-based hedge fund BP Capital Management LP, plans to spend $58 million to promote his idea of building a wind power corridor in the Midwest to replace power produced from natural gas. The natural gas would be used for transportation until new technology discovers ways to increase the use of all alternative energy sources, such as wind, nuclear, coal, biofuels, geothermal and solar.
"I'm for every one of them," Pickens said. "Because this is American. That's our arsenal to work with."
The U.S. imports 70 percent of its oil, at an annual cost of $700 billion, which Pickens called a "ticking bomb" that is threatening our economy and security.
Pickens acknowledged that his plan would be expensive, both in developing the alternative energy and finding ways to transmit it. But he said if nothing changes, the country will be importing 80 percent of its oil in 10 years, at $200 to $300 a barrel.
"We are broke at that point," he said.
Strong leaders are needed to convince Americans that the expense and hassles of changing the nation's energy dependence is worth the effort, he said.
"You have to have the right leadership that's going to get up and sell this and say, 'Let me tell you we can do it on our own, we have resources to do it on our own,'" Pickens said. "People have got to understand this has to be done, the country has got to do this."
In a talk earlier in the day, U.S. Agriculture Secretary Ed Schafer also discussed his support for all types of energy sources.
Schafer said he believes the country doesn't have a national energy policy because members of Congress work against each other to champion energy sources that are abundant in their states.
"We don't look at the overall policy, we say we don't have enough money, we don't have the resources, so therefore, I've got to get enough money for wind versus coal. ... Because of that, we have fractured the focus so much that don't get the overall policy," he said.
"It behooves us to put forward a national energy policy," said Schafer. "Until we have an overall, overarching energy policy to say this is where the country is going to go ... we're not going to move in the right direction."
"What I wanted when I started this campaign of mine, what my plan was, was to get it elevated so the candidates were going to talk about it," Pickens said Monday at a meeting of the Society of American Business Editors and Writers Inc.
Pickens said he met with both Republican presidential nominee John McCain and Democratic nominee candidate Barack Obama to discuss his "Pickens Plan" for energy independence, and "both of them were 10s as far as interest."
While McCain focused on nuclear energy and Obama is interested in hybrid cars, it is important that the issue is on the front burner of the presidential campaign, Pickens said.
"I don't even want to talk politics, I don't even want to waste time on anything politically related," he said. "This is totally nonpartisan, this is something both parties can work on together."
Pickens, an 80-year-old who now heads the Dallas-based hedge fund BP Capital Management LP, plans to spend $58 million to promote his idea of building a wind power corridor in the Midwest to replace power produced from natural gas. The natural gas would be used for transportation until new technology discovers ways to increase the use of all alternative energy sources, such as wind, nuclear, coal, biofuels, geothermal and solar.
"I'm for every one of them," Pickens said. "Because this is American. That's our arsenal to work with."
The U.S. imports 70 percent of its oil, at an annual cost of $700 billion, which Pickens called a "ticking bomb" that is threatening our economy and security.
Pickens acknowledged that his plan would be expensive, both in developing the alternative energy and finding ways to transmit it. But he said if nothing changes, the country will be importing 80 percent of its oil in 10 years, at $200 to $300 a barrel.
"We are broke at that point," he said.
Strong leaders are needed to convince Americans that the expense and hassles of changing the nation's energy dependence is worth the effort, he said.
"You have to have the right leadership that's going to get up and sell this and say, 'Let me tell you we can do it on our own, we have resources to do it on our own,'" Pickens said. "People have got to understand this has to be done, the country has got to do this."
In a talk earlier in the day, U.S. Agriculture Secretary Ed Schafer also discussed his support for all types of energy sources.
Schafer said he believes the country doesn't have a national energy policy because members of Congress work against each other to champion energy sources that are abundant in their states.
"We don't look at the overall policy, we say we don't have enough money, we don't have the resources, so therefore, I've got to get enough money for wind versus coal. ... Because of that, we have fractured the focus so much that don't get the overall policy," he said.
"It behooves us to put forward a national energy policy," said Schafer. "Until we have an overall, overarching energy policy to say this is where the country is going to go ... we're not going to move in the right direction."
Monday, September 8, 2008
Shell Signs Iraqi Natural Gas Development Deal!
BAGHDAD (AP) — Iraq's Cabinet approved an initial gas agreement Sunday between the Oil Ministry and Royal Dutch Shell PLC to invest in a joint venture to tap natural gas in southern Iraq, a government statement said.
The agreement calls for establishing a joint venture between the state-run South Oil Co. and Shell to exploit the fields, the statement added without any other details.
In June, Oil Minister Hussain al-Shahristani told parliament that Iraq was expected to finalize a deal this summer that would enable it to exploit flared associated gas for domestic use and exports.
Shell had approached the Oil Ministry in December with its plans and since then meetings have been held outside Iraq, mainly in Damascus, Syria.
Shell is expected to invest $3 billion to $4 billion over five years to gather at least 500-600 million cubic feet of flared gas per day from the southern fields.
The state-run South Oil Co. is expected to control 51 percent of the venture, while Shell would hold the remaining 49 percent.
The agreement provides for construction of a number of liquefied natural gas facilities, the statement said.
According to Iraqi oil officials, Iraq loses approximately $40 million worth of natural gas each day because it is either re-injected into wells or burned due to a lack of sufficient infrastructure to exploit it for consumption or export.
The agreement would be Iraq's second major hydrocarbon deal since the U.S.-led invasion of 2003 that toppled Saddam Hussein.
Last week, the Cabinet approved a $3 billion deal with China to develop the Ahdab oil field in southern Iraq.
Under the contract, China National Petroleum Corp. will develop the field for 20 years. It's expected to produce up to 25,000 barrels per day after three years, and eventually reach 125,000 barrels per day.
The ministry also said it was negotiating with Shell to conduct output tests for the Akkas gas field in western Iraq, which has estimated reserves of more than 2.15 trillion cubic feet.
The field, which has five wells that are ready to be interconnected, could produce up to 50 million cubic feet a day as a first stage and could be increased to 500 million cubic feet a day, it said. Gas would be pumped through Syria and Turkey to consumers in Europe.
Shell is also negotiating a one-year service contract with the Iraqi Oil Ministry to develop Missan and Kirkuk oil fields. It is one of at least five contracts Iraq is negotiating with oil majors to boost its current output of 2.5 million barrels per day.
Iraq has the world's third-largest oil reserves with an estimated 115 billion barrels. It also sits on an estimated 112 trillion cubic feet of natural gas reserves, according to the ministry.
The agreement calls for establishing a joint venture between the state-run South Oil Co. and Shell to exploit the fields, the statement added without any other details.
In June, Oil Minister Hussain al-Shahristani told parliament that Iraq was expected to finalize a deal this summer that would enable it to exploit flared associated gas for domestic use and exports.
Shell had approached the Oil Ministry in December with its plans and since then meetings have been held outside Iraq, mainly in Damascus, Syria.
Shell is expected to invest $3 billion to $4 billion over five years to gather at least 500-600 million cubic feet of flared gas per day from the southern fields.
The state-run South Oil Co. is expected to control 51 percent of the venture, while Shell would hold the remaining 49 percent.
The agreement provides for construction of a number of liquefied natural gas facilities, the statement said.
According to Iraqi oil officials, Iraq loses approximately $40 million worth of natural gas each day because it is either re-injected into wells or burned due to a lack of sufficient infrastructure to exploit it for consumption or export.
The agreement would be Iraq's second major hydrocarbon deal since the U.S.-led invasion of 2003 that toppled Saddam Hussein.
Last week, the Cabinet approved a $3 billion deal with China to develop the Ahdab oil field in southern Iraq.
Under the contract, China National Petroleum Corp. will develop the field for 20 years. It's expected to produce up to 25,000 barrels per day after three years, and eventually reach 125,000 barrels per day.
The ministry also said it was negotiating with Shell to conduct output tests for the Akkas gas field in western Iraq, which has estimated reserves of more than 2.15 trillion cubic feet.
The field, which has five wells that are ready to be interconnected, could produce up to 50 million cubic feet a day as a first stage and could be increased to 500 million cubic feet a day, it said. Gas would be pumped through Syria and Turkey to consumers in Europe.
Shell is also negotiating a one-year service contract with the Iraqi Oil Ministry to develop Missan and Kirkuk oil fields. It is one of at least five contracts Iraq is negotiating with oil majors to boost its current output of 2.5 million barrels per day.
Iraq has the world's third-largest oil reserves with an estimated 115 billion barrels. It also sits on an estimated 112 trillion cubic feet of natural gas reserves, according to the ministry.
Sunday, September 7, 2008
India Natural Gas Rig Closed After Fire!
An oil rig deployed by Oil and Natural Gas Corporation Ltd (ONGC) in Bombay High South field caught fire on Saturday afternoon due to “mechanical malfunction”. No loss of life is reported but five contractual workers were injured, an ONGC spokesperson said.
There were a total of 87 workers on the rig. The fire, which broke out at 1.50 pm, shut down a non-oil producing well, but there was no loss of production from other wells. Bombay High North and South fields together account for around half of the total oil produced in the country and around 13 per cent of the total available gas.
The rig, belonging to US-based Pride International, was drilling an exploration well in the Bombay High South, around 160 kms from the Mumbai coast. The rig was drilling a cluster of wells under the Bombay High South Redevelopment programme, which was undertaken to enhance the production.
Drilling operations have been shut due to the fire, which was extinguished within an hour, the company said. Another rig hired from US-based Pride International, Pride Hawaii is also operating in the Bombay High South Redevelopment programme and its working well, the ONGC spokesperson said.
This is not the first time there has been a fire in the Bombay High oil and gas fields. On July 27, 2005, a shipping vessel crashed on the Bombay High North platform resulting a fire that killed 11 people.
It also resulted in loss in production of 110,000 barrels per day (bpd) of oil, or around 16 per cent of the country’s total oil production.
There were a total of 87 workers on the rig. The fire, which broke out at 1.50 pm, shut down a non-oil producing well, but there was no loss of production from other wells. Bombay High North and South fields together account for around half of the total oil produced in the country and around 13 per cent of the total available gas.
The rig, belonging to US-based Pride International, was drilling an exploration well in the Bombay High South, around 160 kms from the Mumbai coast. The rig was drilling a cluster of wells under the Bombay High South Redevelopment programme, which was undertaken to enhance the production.
Drilling operations have been shut due to the fire, which was extinguished within an hour, the company said. Another rig hired from US-based Pride International, Pride Hawaii is also operating in the Bombay High South Redevelopment programme and its working well, the ONGC spokesperson said.
This is not the first time there has been a fire in the Bombay High oil and gas fields. On July 27, 2005, a shipping vessel crashed on the Bombay High North platform resulting a fire that killed 11 people.
It also resulted in loss in production of 110,000 barrels per day (bpd) of oil, or around 16 per cent of the country’s total oil production.
Saturday, September 6, 2008
U.S. Natural Gas Production Significantly Being Increased
Natural Gas production is going up by a lot in the United States. This was noted at Peak Oil Debunked about a month ago.
The peak oil people such as Mike Ruppert and Matt Simmons were saying in 2003 and since then that natural gas production was heading for a sharp decline.
Now even some peak oil people are changing their tune. Gail at the oildrum has agreed that natural gas production will increase in the USA
Natural gas production can be ramped up by nearly 50% by 2020. My [Gail at theoildrum.com ] interpretation of what is happening is that there has been a technological breakthrough, probably in the area of shale gas production of natural gas.
Stocks benefiting from the Haynesville natural gas play
Chesapeake (CHK) is the diversified approach, Petrohawk (HK) is the concentrated way, and Goodrich (GDP) seems to be the small cap approach. Haynesville is a southeastern shale deposit in Arkansas, Louisiana, and Texas.
The U.S. has enough natural gas resources to last up to 118 years, or 2,247 trillion cubic feet (Tcf), according to the study by Navigant Consulting for the American Clean Skies Foundation based on a mid-2008 estimates.
Canada Natural gas and oilsands
In Canada, The Horn River basin as 500 trillion cubic feet in place. 9-16tcf from the Ootla region of the Horn River for Apache Corp alone.
Canada's Oil and Gas sector outlook from June 2008.
B.C.'s Horn River Basin, near the Northwest Territories, has generated early estimates upwards of 28 tcf (trillion cubic feet) in potential shale gas reserves. To the south lies the Montney sand, shale and siltstone tight gas play, which the B.C. government pegs at 80 tcf of tight gas in place.
In the Saint Lawrence Lowlands of Quebec, Forest Oil Corp. compares its Utica shale gas discovery (estimated four tcf potential) to the legendary Barnett shale in Texas. On the East Coast, wildcatters are testing the potential of the Frederick Brook shale formation of Nova Scotia and New Brunswick.
In a February report, Raymond James Ltd. calculated that a move from vertical wells to horizontal improved Montney economics from break-even to a 27% expected internal rate of return.
Massive cost increases have bedeviled development of Canada's Arctic gas potential. In the Mackenzie Delta, three natural gas discoveries total 5.8 tcf. Further north in the Arctic islands, 16 gas discoveries amount to a further 17 tcf. Benoit Beauchamp, executive director of the University of Calgary's Arctic Institute of North America and a former Geological Survey of Canada field geologist in the Far North, estimates the remote region's potential at 117 tcf of gas plus nearly four billion barrels of oil.
Canada's oilsands motherlode - Alberta estimates that its buried treasure totals 1.7 trillion barrels of bitumen in place - could require fresh capital in the stunning range of $300 billion. That estimate, released by the Canadian Energy Research Institute in November, assumes that all announced projects by oilsands producers and upgraders proceed. Production in that case would soar to six million barrels per day by 2027. David McColl, an economist with the Calgary-based think tank, says capital expenditure on that scale would require a long-term stable oil price upwards of $60 (U.S.) WTI per barrel.
The peak oil people such as Mike Ruppert and Matt Simmons were saying in 2003 and since then that natural gas production was heading for a sharp decline.
Now even some peak oil people are changing their tune. Gail at the oildrum has agreed that natural gas production will increase in the USA
Natural gas production can be ramped up by nearly 50% by 2020. My [Gail at theoildrum.com ] interpretation of what is happening is that there has been a technological breakthrough, probably in the area of shale gas production of natural gas.
Stocks benefiting from the Haynesville natural gas play
Chesapeake (CHK) is the diversified approach, Petrohawk (HK) is the concentrated way, and Goodrich (GDP) seems to be the small cap approach. Haynesville is a southeastern shale deposit in Arkansas, Louisiana, and Texas.
The U.S. has enough natural gas resources to last up to 118 years, or 2,247 trillion cubic feet (Tcf), according to the study by Navigant Consulting for the American Clean Skies Foundation based on a mid-2008 estimates.
Canada Natural gas and oilsands
In Canada, The Horn River basin as 500 trillion cubic feet in place. 9-16tcf from the Ootla region of the Horn River for Apache Corp alone.
Canada's Oil and Gas sector outlook from June 2008.
B.C.'s Horn River Basin, near the Northwest Territories, has generated early estimates upwards of 28 tcf (trillion cubic feet) in potential shale gas reserves. To the south lies the Montney sand, shale and siltstone tight gas play, which the B.C. government pegs at 80 tcf of tight gas in place.
In the Saint Lawrence Lowlands of Quebec, Forest Oil Corp. compares its Utica shale gas discovery (estimated four tcf potential) to the legendary Barnett shale in Texas. On the East Coast, wildcatters are testing the potential of the Frederick Brook shale formation of Nova Scotia and New Brunswick.
In a February report, Raymond James Ltd. calculated that a move from vertical wells to horizontal improved Montney economics from break-even to a 27% expected internal rate of return.
Massive cost increases have bedeviled development of Canada's Arctic gas potential. In the Mackenzie Delta, three natural gas discoveries total 5.8 tcf. Further north in the Arctic islands, 16 gas discoveries amount to a further 17 tcf. Benoit Beauchamp, executive director of the University of Calgary's Arctic Institute of North America and a former Geological Survey of Canada field geologist in the Far North, estimates the remote region's potential at 117 tcf of gas plus nearly four billion barrels of oil.
Canada's oilsands motherlode - Alberta estimates that its buried treasure totals 1.7 trillion barrels of bitumen in place - could require fresh capital in the stunning range of $300 billion. That estimate, released by the Canadian Energy Research Institute in November, assumes that all announced projects by oilsands producers and upgraders proceed. Production in that case would soar to six million barrels per day by 2027. David McColl, an economist with the Calgary-based think tank, says capital expenditure on that scale would require a long-term stable oil price upwards of $60 (U.S.) WTI per barrel.
Friday, September 5, 2008
Compressed Natural Gas Station for University CNG Cars
The University of Denver has installed a compressed natural gas fueling station for 15 vehicles that have been converted to burn natural gas instead of gasoline.
It’s believed to be a first among Colorado universities.
The fuel is cheaper and emits less carbon than gasoline, the university said Thursday.
The cars were filling up at a retail natural gas station, but now can fill up on campus, said Allan Wilson, DU’s director of building services.
Since the program started, the cars have cut fuel costs for the university by at least $12,000 and kept 9.5 tons of carbon out of the atmosphere, Wilson said in a statement.
The new station, which draws natural gas off existing lines and compresses it, enables DU to run vehicles at the equivalent of buying $2.25-a-gallon gasoline, the university said.
DU said it used a $180,000 grant from the Denver-based Strategic Environmental Project Pipeline (StEPP) Foundation, a nonprofit dedicated to clean energy, to convert 15 vehicles serving facilities maintenance, parking services and procurement to use compressed natural gas Each conversion costs about $12,000, and vehicles still can burn gasoline in a pinch.
It’s believed to be a first among Colorado universities.
The fuel is cheaper and emits less carbon than gasoline, the university said Thursday.
The cars were filling up at a retail natural gas station, but now can fill up on campus, said Allan Wilson, DU’s director of building services.
Since the program started, the cars have cut fuel costs for the university by at least $12,000 and kept 9.5 tons of carbon out of the atmosphere, Wilson said in a statement.
The new station, which draws natural gas off existing lines and compresses it, enables DU to run vehicles at the equivalent of buying $2.25-a-gallon gasoline, the university said.
DU said it used a $180,000 grant from the Denver-based Strategic Environmental Project Pipeline (StEPP) Foundation, a nonprofit dedicated to clean energy, to convert 15 vehicles serving facilities maintenance, parking services and procurement to use compressed natural gas Each conversion costs about $12,000, and vehicles still can burn gasoline in a pinch.
Thursday, September 4, 2008
Natural Gas Cars Need Natural Gas Filling Stations
PHOENIX, Sept. 3 (UPI) -- Less pollution and cheaper fuel prices have not triggered a high U.S. demand for natural gas powered cars, industry observers said.
Compressed natural gas-powered cars "pretty much beat the socks off any other vehicle out there," said Al Brown, a former CNG Honda Civic owner, who recently purchased Toyota Prius, a hybrid that runs on gasoline and electricity, The Arizona Republic reported Wednesday.
The problem, Brown said, was the lack of demand for compressed natural gas led to the closing of two CNG stations he frequented. Eventually, "I had to drive significantly out of my way -- 10 miles round trip twice a week," to refill his Honda.
In Arizona, the 6,000 owners of CNG cars find their numbers are shrinking, causing refilling stations to close and increasing worries about who will tend to repairs. With a lack of infrastructure and repair support, CNG car owners are finding their vehicles harder to sell, the Republic reported.
However, some believe CNG cars still have a future.
"Just listen to the politicians. They're all talking about it now," Randy Fleischhauer, a retired risk manager attorney told the newspaper.
Compressed natural gas-powered cars "pretty much beat the socks off any other vehicle out there," said Al Brown, a former CNG Honda Civic owner, who recently purchased Toyota Prius, a hybrid that runs on gasoline and electricity, The Arizona Republic reported Wednesday.
The problem, Brown said, was the lack of demand for compressed natural gas led to the closing of two CNG stations he frequented. Eventually, "I had to drive significantly out of my way -- 10 miles round trip twice a week," to refill his Honda.
In Arizona, the 6,000 owners of CNG cars find their numbers are shrinking, causing refilling stations to close and increasing worries about who will tend to repairs. With a lack of infrastructure and repair support, CNG car owners are finding their vehicles harder to sell, the Republic reported.
However, some believe CNG cars still have a future.
"Just listen to the politicians. They're all talking about it now," Randy Fleischhauer, a retired risk manager attorney told the newspaper.
Wednesday, September 3, 2008
BP Purchases Arkansas Natural Gas Assets from Chesapeake
BP America has agreed to purchase a 25 percent stake in Chesapeake Energy Corp.’s Fayetteville Shale assets in Arkansas for $1.9 billion.
As part of the agreement, Houston-based BP America will pay $1.1 billion in cash, and the rest will come by way of funding Chesapeake’s 75 percent share of drilling and completion expenditures until the $800 million is met.
The deal includes about 540,000 net acres of leasehold, of which BP America will own about 135,000 net acres. The assets have a daily net production of about 180 million cubic feet of natural gas equivalent.
Oklahoma City-based Chesapeake (NYSE: CHK) plans to continue acquiring leaseholds in the Fayetteville Shale play, and BP will have the right to a 25 percent participation in any such additional leasehold.
BP America (NYSE: BP) expects to close the deal this month.
As part of the agreement, Houston-based BP America will pay $1.1 billion in cash, and the rest will come by way of funding Chesapeake’s 75 percent share of drilling and completion expenditures until the $800 million is met.
The deal includes about 540,000 net acres of leasehold, of which BP America will own about 135,000 net acres. The assets have a daily net production of about 180 million cubic feet of natural gas equivalent.
Oklahoma City-based Chesapeake (NYSE: CHK) plans to continue acquiring leaseholds in the Fayetteville Shale play, and BP will have the right to a 25 percent participation in any such additional leasehold.
BP America (NYSE: BP) expects to close the deal this month.
Tuesday, September 2, 2008
Dominion Natural Gas Investment $1 Billion
By Kasey, Pam
As West Virginia's natural gas industry grows, producers want to move more gas across and out of the state.
Now, Dominion Transmission is proposing a $1 billion project to help get that gas to eastern markets.
The utility presented its Appalachian Gateway proposal at a July 22 meeting for natural gas producers at Stonewall Resort and Conference Center.
Marc Halbritter, Dominion Transmission's managing director for commercial activities, illustrated growth in the state's industry by referencing topics that recently have been in the news: growth in production in general and the anticipated development of the Marcellus Shale formation.
"Local producers are faced with the potential that we won't have the infrastructure that we need in West Virginia to get gas to the point where we can take it out of state," Halbritter said.
Seeing this coming, Dominion asked producers in April how much gas they'd like to be able to move.
The response, Halbritter said, was "overwhelming."
"The requests for potential service were nearly three times the volume of gas Dominion currently handles," he said.
"Based on what they told us, we are presenting to them the facilities we would build to move their gas from West Virginia out of state to Pennsylvania," he said. That would get it to a southwestern Pennsylvania hub where Dominion can send it east.
The proposal includes 122 miles of new pipe in West Virginia and about 40,000 horsepower of compression, according to Halbritter.
"This is more than a 50 percent increase in the current volume," he said.
It's a large investment, too.
"We are talking about investing, in just the pipeline facilities, in the neighborhood of $660 million," Halbritter said.
Unlike the "interruptible" transmission that West Virginia producers have lived with in the past, this new transmission would be "firm": under contract and dedicated.
Dominion's proposed investment doesn't stop there.
"We have planned as a result of producer interest as much as $87 million in what we call gathering facilities: smaller diameter, lower pressure pipes that we use to get production to larger diameter, higher pressure pipes," Halbritter said. "And over $275 million in processing facilities ... to make the gas of a quality that people can burn in their homes or industrial plants."
In all, the investments would total more than $1 billion in natural gas processing and transmission facilities.
"This is a big deal for Dominion," Halbritter said. "We do billion dollar projects but we don't do a lot of them, so this is one of our largest projects."
The next step is for producers to make commitments. They have to let Dominion know by mid-September exactly how much transmission capacity they're willing to lease under 10-year contracts.
Those commitments will come from the state's biggest producers such as Dominion Exploration & Production, Equitable Production, Cabot Oil & Gas, Chesapeake Energy Corp. and others. In fact, the biggest seven companies account for about 70 percent of the state's production.
But Halbritter said smaller producers will not be overlooked. He said he expects commitments to come from some of the state's hundreds of smaller producers.
Once the producer commitments are in place, it will take about a year to apply to the Federal Energy Regulatory Commission about a year for the FERC to make a decision, and a little under a year to build the facilities.
If all moves as Dominion proposes, Halbritter expects the project to be in place by the end of 2011.
To expand the natural gas transmission infrastructure, Dominion in some places will replace smaller pipes with larger ones. In others, it will need to lay new pipe, and that will require the purchase of rights of way.
Some of the work will be done by Dominion employees and some will be bid out, Halbritter said. Without producer commitments yet in place, he was unable to say how many people will be required to construct the new pipeline.
As West Virginia's natural gas industry grows, producers want to move more gas across and out of the state.
Now, Dominion Transmission is proposing a $1 billion project to help get that gas to eastern markets.
The utility presented its Appalachian Gateway proposal at a July 22 meeting for natural gas producers at Stonewall Resort and Conference Center.
Marc Halbritter, Dominion Transmission's managing director for commercial activities, illustrated growth in the state's industry by referencing topics that recently have been in the news: growth in production in general and the anticipated development of the Marcellus Shale formation.
"Local producers are faced with the potential that we won't have the infrastructure that we need in West Virginia to get gas to the point where we can take it out of state," Halbritter said.
Seeing this coming, Dominion asked producers in April how much gas they'd like to be able to move.
The response, Halbritter said, was "overwhelming."
"The requests for potential service were nearly three times the volume of gas Dominion currently handles," he said.
"Based on what they told us, we are presenting to them the facilities we would build to move their gas from West Virginia out of state to Pennsylvania," he said. That would get it to a southwestern Pennsylvania hub where Dominion can send it east.
The proposal includes 122 miles of new pipe in West Virginia and about 40,000 horsepower of compression, according to Halbritter.
"This is more than a 50 percent increase in the current volume," he said.
It's a large investment, too.
"We are talking about investing, in just the pipeline facilities, in the neighborhood of $660 million," Halbritter said.
Unlike the "interruptible" transmission that West Virginia producers have lived with in the past, this new transmission would be "firm": under contract and dedicated.
Dominion's proposed investment doesn't stop there.
"We have planned as a result of producer interest as much as $87 million in what we call gathering facilities: smaller diameter, lower pressure pipes that we use to get production to larger diameter, higher pressure pipes," Halbritter said. "And over $275 million in processing facilities ... to make the gas of a quality that people can burn in their homes or industrial plants."
In all, the investments would total more than $1 billion in natural gas processing and transmission facilities.
"This is a big deal for Dominion," Halbritter said. "We do billion dollar projects but we don't do a lot of them, so this is one of our largest projects."
The next step is for producers to make commitments. They have to let Dominion know by mid-September exactly how much transmission capacity they're willing to lease under 10-year contracts.
Those commitments will come from the state's biggest producers such as Dominion Exploration & Production, Equitable Production, Cabot Oil & Gas, Chesapeake Energy Corp. and others. In fact, the biggest seven companies account for about 70 percent of the state's production.
But Halbritter said smaller producers will not be overlooked. He said he expects commitments to come from some of the state's hundreds of smaller producers.
Once the producer commitments are in place, it will take about a year to apply to the Federal Energy Regulatory Commission about a year for the FERC to make a decision, and a little under a year to build the facilities.
If all moves as Dominion proposes, Halbritter expects the project to be in place by the end of 2011.
To expand the natural gas transmission infrastructure, Dominion in some places will replace smaller pipes with larger ones. In others, it will need to lay new pipe, and that will require the purchase of rights of way.
Some of the work will be done by Dominion employees and some will be bid out, Halbritter said. Without producer commitments yet in place, he was unable to say how many people will be required to construct the new pipeline.
Subscribe to:
Posts (Atom)