http://www.bloomberg.com/apps/news?pid=20602099&sid=a0yJWuO8vXs4
By Reg Curren
July 31 (Bloomberg) -- Natural gas fell for the fourth day this week after Chesapeake Energy Corp., the second largest U.S. gas producer, said output increased in the second quarter.
Production rose 4 percent from the first quarter and was up 5 percent from a year earlier, the Oklahoma City-based company said in a statement late yesterday. Gas inventories already are the highest for this time of year since the Energy Department began keeping records in 1994.
“Oil and gas operators have come out with some pretty robust results so you have concerns that supply isn’t going to roll over fast enough” to reduce stockpiles, said Scott Hanold, an analyst at RBC Capital Markets in Minneapolis. “You’re going to have storage fill up and there will be gas-on-gas competition.”
Natural gas for September delivery fell 9.6 cents, or 2.6 percent, to $3.647 per million British thermal units at 9:38 a.m. on the New York Mercantile Exchange. Gas prices have fallen 4.9 percent this month and are down 35 percent this year.
Natural gas extended losses after a U.S. Commerce Department report showed the recession was deeper than first estimated and consumer spending shrank more than twice as much as forecast.
Lower consumer spending may hamper the economy’s recovery and demand for gas by industry, which accounts for 29 percent of U.S. consumption. The U.S. gross domestic product shrank at a 1 percent annual pace in the second quarter.
“One of the weak points for gas has been industrial demand and that’s obviously GDP-related,” Hanold said.
Total gas used by industrial consumers, including factories, steel mills and chemical plants, plunged 13 percent in the first five months of 2009 to 2.576 trillion cubic feet from the same period a year earlier, the Energy Department said on July 29.
Gas inventories increased by 71 billion cubic feet in the week ended July 24 to 3.023 trillion, the Energy Department said yesterday. The amount of gas in storage for the week compared to the five-year average widened to 19 percent from 18 percent.
To contact the reporter on this story: Reg Curren in Calgary at rcurren@bloomberg.net.
Last Updated: July 31, 2009 09:51 EDT
Friday, July 31, 2009
Thursday, July 30, 2009
Natural Gas in Ohio
http://www.ohio.com/editorial/opinions/51842452.html
Faced with the prospect of a natural gas well about 180 feet from their home in Stow, Dan and Denise Tonelli have no local officials to whom they can turn. The reason? A state law passed in 2004 ended the power of local governments to exert any control over oil and gas drilling within local boundaries. As explained Monday by Jim Carney, a Beacon Journal staff writer, the Tonellis almost certainly will be forced into joining a group of nearby homeowners in a mandatory arrangement.
The couple may appeal to a special board that advises the Ohio Department of Natural Resources, but the panel is stacked with oil and gas industry representatives. For the past two years, the panel has upheld these mandatory deals, the ODNR approving virtually all permit requests. Royalties are of little concern to the Stow couple. Although the gas well would bring much-needed cash to the Stow Community United Church of Christ, on whose land it would be drilled, the loss of privacy and fears about safety have the Tonellis considering selling their home.
Evidence that the 2004 law, strongly backed by oil and gas interests, went too far continues to pile up, especially in densely populated Northeast Ohio. The law, which permits drilling as close as 100 feet to a home, is considered one of the most industry-friendly in the country. (The old standard in Stow was twice as much, 200 feet.) Drilling interests, whose profits support a powerful lobbying arm, were close to opening public parks to their rigs until the language was stripped from the recent budget bill.
Returning a stronger role for local governments to control oil and gas drilling in residential areas is long overdue. In suburban and urban neighborhoods, the tradeoffs demand a full airing, the marginal value of more oil and gas in the global market carefully balanced against the negative aspects of drilling and operating wells in residential neighborhoods.
This week, state Sen. Tim Grendell, a Geauga County Republican, plans to introduce legislation that would allow local governments to adopt a set of uniform standards, among them a 500-foot buffer between a well and a home. That's a start. Local governments deserve greater latitude to listen and respond to local voices opposing oil and gas drillers out to make a profit in their back yards.
Faced with the prospect of a natural gas well about 180 feet from their home in Stow, Dan and Denise Tonelli have no local officials to whom they can turn. The reason? A state law passed in 2004 ended the power of local governments to exert any control over oil and gas drilling within local boundaries. As explained Monday by Jim Carney, a Beacon Journal staff writer, the Tonellis almost certainly will be forced into joining a group of nearby homeowners in a mandatory arrangement.
The couple may appeal to a special board that advises the Ohio Department of Natural Resources, but the panel is stacked with oil and gas industry representatives. For the past two years, the panel has upheld these mandatory deals, the ODNR approving virtually all permit requests. Royalties are of little concern to the Stow couple. Although the gas well would bring much-needed cash to the Stow Community United Church of Christ, on whose land it would be drilled, the loss of privacy and fears about safety have the Tonellis considering selling their home.
Evidence that the 2004 law, strongly backed by oil and gas interests, went too far continues to pile up, especially in densely populated Northeast Ohio. The law, which permits drilling as close as 100 feet to a home, is considered one of the most industry-friendly in the country. (The old standard in Stow was twice as much, 200 feet.) Drilling interests, whose profits support a powerful lobbying arm, were close to opening public parks to their rigs until the language was stripped from the recent budget bill.
Returning a stronger role for local governments to control oil and gas drilling in residential areas is long overdue. In suburban and urban neighborhoods, the tradeoffs demand a full airing, the marginal value of more oil and gas in the global market carefully balanced against the negative aspects of drilling and operating wells in residential neighborhoods.
This week, state Sen. Tim Grendell, a Geauga County Republican, plans to introduce legislation that would allow local governments to adopt a set of uniform standards, among them a 500-foot buffer between a well and a home. That's a start. Local governments deserve greater latitude to listen and respond to local voices opposing oil and gas drillers out to make a profit in their back yards.
Wednesday, July 29, 2009
CNX Gas Leasing in the Marcellus Shale of West Virginia and Pennsylvania
http://www.philly.com/philly/wires/ap/news/state/pennsylvania/20090728_ap_cnxgasacquiresmorewvapaleases.html
CNX Gas acquires more WVa, Pa leases
The Associated Press
CHARLESTON, W.Va. - CNX Gas Corp. says it's leased approximately 40,000 acres of Marcellus Shale natural gas property in West Virginia and Pennsylvania.
Canonsburg, Pa.-based CNX said Tuesday the separate leases with its former corporate parent Consol Energy and a Columbia Energy Group subsidiary increase its Marcellus holdings to 230,000 acres. The Marcellus formation is believed to hold vast amounts of gas deep under West Virginia, Pennsylvania and New York.
CNX says the property is in Marshall, Monongalia and Wetzel counties and Pennsylvania's Washington and Greene counties.
Consol spun off CNX Gas as a separate public company in 2005, but still holds the majority of its stock.
CNX Gas acquires more WVa, Pa leases
The Associated Press
CHARLESTON, W.Va. - CNX Gas Corp. says it's leased approximately 40,000 acres of Marcellus Shale natural gas property in West Virginia and Pennsylvania.
Canonsburg, Pa.-based CNX said Tuesday the separate leases with its former corporate parent Consol Energy and a Columbia Energy Group subsidiary increase its Marcellus holdings to 230,000 acres. The Marcellus formation is believed to hold vast amounts of gas deep under West Virginia, Pennsylvania and New York.
CNX says the property is in Marshall, Monongalia and Wetzel counties and Pennsylvania's Washington and Greene counties.
Consol spun off CNX Gas as a separate public company in 2005, but still holds the majority of its stock.
Tuesday, July 28, 2009
Pennsylvania Eyes Marcellus Shale Development
Penn State Study: Marcellus Shale Development Expected to Create 98,000 Pennsylvania Jobs by 2010, $14.17 Billion Impact
Proposed Severance Tax Would Hurt Jobs, Investment, and Result in $1.4 Billion in Less State and Local Tax Revenue
*** Audio coverage from a news conference held earlier this morning about the study will be available today on the PA Marcellus Web site. Visit www.pamarcellus.com after 3:00 p.m. to access the audio feed.***
HARRISBURG, Pa., July 27 /PRNewswire/ -- Marcellus Shale development will pump $14.17 billion into the state's economy in 2010 and create more than 98,000 jobs, while generating $800 million in state and local tax revenues, according to an economic study completed by the Pennsylvania State University for the Marcellus Shale Committee and the Pennsylvania House Natural Gas Caucus.
The study notes a consistent increase in annual drilling and projects a $25 billion contribution to the Commonwealth's economy in the year 2020. This level of activity would generate almost $1.4 billion in state and local tax revenue and create more than 176,000 new jobs.
The curtailment of drilling activity that would result from the imposition of the newly proposed severance tax would generate $1.4 billion less state and local total tax revenue between now and 2020 than if the industry is allowed to grow without the new proposed tax. It would also result in less job creation and overall economic benefits in Pennsylvania. No other mineral in Pennsylvania is subject to such tax. Other states competing for limited investment dollars reduce taxes on high cost shale development.
The House Natural Gas Caucus, a bi-partisan group of 56 legislators from across Pennsylvania, announced the findings of a study that was compiled with economic data provided by the member companies of the Marcellus Shale Committee.
"This study validates what is being experienced in my district and in other communities around the state where drilling in the Marcellus Shale has taken a foothold, focusing on real economic growth and good jobs for people in a number of fields," said State Rep. Tim Solobay (D-Washington). "Pennsylvania has the hardest-working job force in America and the Marcellus represents an opportunity to prove that we're up for the challenge of developing the largest, natural gas field in the United States."
"During difficult economic times such as this, the findings from Penn State bring exciting news that will positively impact nearly every facet of Pennsylvania's economy," said State Rep. Brian Ellis (R-Butler). "We have a once-in-a-generation opportunity to improve Pennsylvania's economy and our nation's energy future by embracing and supporting the development of clean-burning natural gas."
Using conservative assumptions for production, commodity prices and related factors, the study found the industry making the following current and future economic contributions to Pennsylvania:
* Natural gas production had a $2.3 billion direct impact on Pennsylvania's economy in 2008, adding more than 29,000 new jobs and $240 million in state and local tax revenue. More than thirty-percent of all tax revenues remain at the level local.
* The industry will contribute a cumulative economic impact to the state of $265 billion by 2020, along with nearly $15 billion in state and local revenue. The study includes direct, indirect and induced jobs, and economic activity from Marcellus Shale development in Pennsylvania.
* Pennsylvania currently imports approximately 75% of its natural gas consumption. If Marcellus activity continues as expected, Pennsylvania could reverse its position as a natural gas importer to a net natural gas exporter by 2014.
The leading researchers on the study are Dr. Timothy Considine, School of Energy Resources Professor of Energy Economics with the Department of Economics and Finance at the University of Wyoming; and Dr. Robert Watson, Emeritus Associate Professor of Petroleum and Natural Gas Engineering and of Environmental Systems Engineering at the Pennsylvania State University, and Chairman of the Technical Advisory Board for the Bureau of Oil and Gas Management of the Pennsylvania Department of Environmental Protection.
The study estimates that the Marcellus Shale may contain 2,445 trillion cubic feet of natural gas reserves in place with recoverable reserves amounting to 489 trillion cubic feet - or enough natural gas to last the entire United States for more than 20 years. Taking into account the other vast reserves of domestic natural gas, the Marcellus Shale will more than likely support Pennsylvania's economy for 100 years or longer.
According to the Energy Information Association (EIA), natural gas usage is expected to increase more than 20% through the 2020 in the United States and 40% worldwide. The EIA also indicates that 57% of all new electric generation will come from natural gas, which is more than all other sources combined.
Proposed Severance Tax Would Hurt Jobs, Investment, and Result in $1.4 Billion in Less State and Local Tax Revenue
*** Audio coverage from a news conference held earlier this morning about the study will be available today on the PA Marcellus Web site. Visit www.pamarcellus.com after 3:00 p.m. to access the audio feed.***
HARRISBURG, Pa., July 27 /PRNewswire/ -- Marcellus Shale development will pump $14.17 billion into the state's economy in 2010 and create more than 98,000 jobs, while generating $800 million in state and local tax revenues, according to an economic study completed by the Pennsylvania State University for the Marcellus Shale Committee and the Pennsylvania House Natural Gas Caucus.
The study notes a consistent increase in annual drilling and projects a $25 billion contribution to the Commonwealth's economy in the year 2020. This level of activity would generate almost $1.4 billion in state and local tax revenue and create more than 176,000 new jobs.
The curtailment of drilling activity that would result from the imposition of the newly proposed severance tax would generate $1.4 billion less state and local total tax revenue between now and 2020 than if the industry is allowed to grow without the new proposed tax. It would also result in less job creation and overall economic benefits in Pennsylvania. No other mineral in Pennsylvania is subject to such tax. Other states competing for limited investment dollars reduce taxes on high cost shale development.
The House Natural Gas Caucus, a bi-partisan group of 56 legislators from across Pennsylvania, announced the findings of a study that was compiled with economic data provided by the member companies of the Marcellus Shale Committee.
"This study validates what is being experienced in my district and in other communities around the state where drilling in the Marcellus Shale has taken a foothold, focusing on real economic growth and good jobs for people in a number of fields," said State Rep. Tim Solobay (D-Washington). "Pennsylvania has the hardest-working job force in America and the Marcellus represents an opportunity to prove that we're up for the challenge of developing the largest, natural gas field in the United States."
"During difficult economic times such as this, the findings from Penn State bring exciting news that will positively impact nearly every facet of Pennsylvania's economy," said State Rep. Brian Ellis (R-Butler). "We have a once-in-a-generation opportunity to improve Pennsylvania's economy and our nation's energy future by embracing and supporting the development of clean-burning natural gas."
Using conservative assumptions for production, commodity prices and related factors, the study found the industry making the following current and future economic contributions to Pennsylvania:
* Natural gas production had a $2.3 billion direct impact on Pennsylvania's economy in 2008, adding more than 29,000 new jobs and $240 million in state and local tax revenue. More than thirty-percent of all tax revenues remain at the level local.
* The industry will contribute a cumulative economic impact to the state of $265 billion by 2020, along with nearly $15 billion in state and local revenue. The study includes direct, indirect and induced jobs, and economic activity from Marcellus Shale development in Pennsylvania.
* Pennsylvania currently imports approximately 75% of its natural gas consumption. If Marcellus activity continues as expected, Pennsylvania could reverse its position as a natural gas importer to a net natural gas exporter by 2014.
The leading researchers on the study are Dr. Timothy Considine, School of Energy Resources Professor of Energy Economics with the Department of Economics and Finance at the University of Wyoming; and Dr. Robert Watson, Emeritus Associate Professor of Petroleum and Natural Gas Engineering and of Environmental Systems Engineering at the Pennsylvania State University, and Chairman of the Technical Advisory Board for the Bureau of Oil and Gas Management of the Pennsylvania Department of Environmental Protection.
The study estimates that the Marcellus Shale may contain 2,445 trillion cubic feet of natural gas reserves in place with recoverable reserves amounting to 489 trillion cubic feet - or enough natural gas to last the entire United States for more than 20 years. Taking into account the other vast reserves of domestic natural gas, the Marcellus Shale will more than likely support Pennsylvania's economy for 100 years or longer.
According to the Energy Information Association (EIA), natural gas usage is expected to increase more than 20% through the 2020 in the United States and 40% worldwide. The EIA also indicates that 57% of all new electric generation will come from natural gas, which is more than all other sources combined.
Monday, July 27, 2009
U.S. Natural Gas Fund Still Active in 2009
By Asjylyn Loder
July 24 (Bloomberg) -- United States Natural Gas Fund, the world’s largest fund in the commodity, bought an off-market gas swap for the first time in a sign that it has outgrown the main markets for fuel futures and swaps.
The $4.4-billion fund purchased a $250 million bilateral swap that isn’t subject to the size limits imposed by the New York Mercantile Exchange, where the fund holds $480-million worth of natural gas futures and swaps. The shift comes as regulators debate imposing similar limits on the Intercontinental Exchange, where the fund has $3.1 billion, or 71 percent, of its holdings.
“We have worked under these assumptions for three and a half years, since we introduced the first fund in oil, that if the funds reached a certain size, they would, for a variety of reasons, including regulatory concerns, have to start to make use of alternatives to the futures,” John Hyland, the fund’s chief investment officer, said today in a telephone interview. “These total return bilateral swaps were the most obvious alternative.”
The exchange-traded fund grew 11-fold since the start of the year to 347.4 million shares before it ran out of new shares on July 7. It is awaiting permission from the Securities and Exchange Commission to sell 1 billion more.
The fund sold 26,950 natural gas swaps cleared by the Intercontinental Exchange Inc., replacing them with the bilateral swap worth $250 million, according to the fund’s Web site.
Oil Fund
Related funds, including the United States Oil Fund, may soon enter into similar trades, Hyland said. Both funds are managed by United States Commodity Funds LLC of Alameda, California. The company also manages funds in heating oil and gasoline, and has asked the SEC for permission to introduce a fund that shorts oil.
For every share sold, the fund makes an investment in natural gas contracts. It holds front-month futures and swaps, selling them as they near expiration and buying the next month.
The natural gas fund rose 45 cents, or 3.5 percent, to $13.33 a share on the New York Stock Exchange. Natural gas for August delivery rose 14.5 cents, or 4.1 percent, to settle at $3.695 per million British thermal units on the Nymex.
CFTC Hearings
The Commodity Futures Trading Commission will hold hearings next week on whether size limits should be imposed on energy commodity investors, including ETFs. The hearings stem from concerns that the gas fund and others like it contributed to the run-up in fuel prices last year.
The fund, which trades under the ticker UNG, said in a regulatory filing today that it does not influence prices.
“Many of the articles published on this topic have stated that UNG’s large size, and the fact that it was the first publicly offered, exchange traded vehicle that offered exposure to natural gas futures, made it a key factor in the rapid rise of natural gas prices in 2008,” the fund said in the filing with the Securities and Exchange Commission.
The fund said that reports “significantly mischaracterize” its role in the market, and that the claims that it influences prices “lack merit.”
The bilateral swaps may come under new regulation in the future, said Tim Evans, an energy analyst with Citi Futures Perspective in New York.
“Since the regulatory picture is in transition, we don’t know at what point the CFTC or other body might still be interested in tracking these exposures and possibly putting limits on them,” Evans said in an e-mail today. “The SEC might be considering that now as they review the UNG application to increase the number of shares.”
Hyland said that the fund will cope with those limits if they arise. “There could be rules that someone could impose and we would have to deal with that.”
To contact the reporter on this story: Asjylyn Loder in New York aloder@bloomberg.net.
July 24 (Bloomberg) -- United States Natural Gas Fund, the world’s largest fund in the commodity, bought an off-market gas swap for the first time in a sign that it has outgrown the main markets for fuel futures and swaps.
The $4.4-billion fund purchased a $250 million bilateral swap that isn’t subject to the size limits imposed by the New York Mercantile Exchange, where the fund holds $480-million worth of natural gas futures and swaps. The shift comes as regulators debate imposing similar limits on the Intercontinental Exchange, where the fund has $3.1 billion, or 71 percent, of its holdings.
“We have worked under these assumptions for three and a half years, since we introduced the first fund in oil, that if the funds reached a certain size, they would, for a variety of reasons, including regulatory concerns, have to start to make use of alternatives to the futures,” John Hyland, the fund’s chief investment officer, said today in a telephone interview. “These total return bilateral swaps were the most obvious alternative.”
The exchange-traded fund grew 11-fold since the start of the year to 347.4 million shares before it ran out of new shares on July 7. It is awaiting permission from the Securities and Exchange Commission to sell 1 billion more.
The fund sold 26,950 natural gas swaps cleared by the Intercontinental Exchange Inc., replacing them with the bilateral swap worth $250 million, according to the fund’s Web site.
Oil Fund
Related funds, including the United States Oil Fund, may soon enter into similar trades, Hyland said. Both funds are managed by United States Commodity Funds LLC of Alameda, California. The company also manages funds in heating oil and gasoline, and has asked the SEC for permission to introduce a fund that shorts oil.
For every share sold, the fund makes an investment in natural gas contracts. It holds front-month futures and swaps, selling them as they near expiration and buying the next month.
The natural gas fund rose 45 cents, or 3.5 percent, to $13.33 a share on the New York Stock Exchange. Natural gas for August delivery rose 14.5 cents, or 4.1 percent, to settle at $3.695 per million British thermal units on the Nymex.
CFTC Hearings
The Commodity Futures Trading Commission will hold hearings next week on whether size limits should be imposed on energy commodity investors, including ETFs. The hearings stem from concerns that the gas fund and others like it contributed to the run-up in fuel prices last year.
The fund, which trades under the ticker UNG, said in a regulatory filing today that it does not influence prices.
“Many of the articles published on this topic have stated that UNG’s large size, and the fact that it was the first publicly offered, exchange traded vehicle that offered exposure to natural gas futures, made it a key factor in the rapid rise of natural gas prices in 2008,” the fund said in the filing with the Securities and Exchange Commission.
The fund said that reports “significantly mischaracterize” its role in the market, and that the claims that it influences prices “lack merit.”
The bilateral swaps may come under new regulation in the future, said Tim Evans, an energy analyst with Citi Futures Perspective in New York.
“Since the regulatory picture is in transition, we don’t know at what point the CFTC or other body might still be interested in tracking these exposures and possibly putting limits on them,” Evans said in an e-mail today. “The SEC might be considering that now as they review the UNG application to increase the number of shares.”
Hyland said that the fund will cope with those limits if they arise. “There could be rules that someone could impose and we would have to deal with that.”
To contact the reporter on this story: Asjylyn Loder in New York aloder@bloomberg.net.
Sunday, July 26, 2009
Exxon's New Natural Gas Frac Process
By ELIZABETH SOUDER / The Dallas Morning News
esouder@dallasnews.com
http://www.dallasnews.com/sharedcontent/dws/bus/stories/DN-exxon_26bus.ART.State.Edition1.3cf4b5d.html
RIFLE, Colo. – Dozens of workers mill around a jumble of pipes and whirring equipment surrounding 10 natural gas wells operated by Exxon Mobil Corp.
At this well site in the desert, 80 miles west of the Rocky Mountains tourism hive, the men load cranes, operate pumps and monitor little red lines on computer screens. The work must happen simultaneously, in a carefully orchestrated ballet, to keep the well costs low – and profit high enough – to be worth the effort of the country's largest oil company.
"We're about 15 minutes away from a new frac being born," Randy Tolman, Exxon's project coordinator for the Piceance Basin, shouts over the noise. He invented this faster method of fracturing, or "fracing," the underground layers of rock and sand to unlock natural gas.
Exxon aims to export the new process to the unconventional natural gas reserves it is accumulating around the world. Drilling for more natural gas could make Exxon a lot of money as Americans demand cleaner fuel because natural gas doesn't emit as much pollution or greenhouse gases as oil and coal when burned.
"It's the bridge fuel," said Amy Jaffe, associate director of Rice University's energy program, adding: "It's going to be a 20-year bridge."
Exxon forecasts that natural gas demand will rise 50 percent by 2030 and outstrip demand for coal.
"Clearly, we anticipate that natural gas will grow much faster than oil or coal. So we see a pretty healthy demand out there in the future for natural gas globally, but even here in North America," chief executive Rex Tillerson said during an analyst meeting earlier this year.
At the gas well site in the desert, Exxon has drilled 10 holes, five of which already produce natural gas. The company's rigs in the Piceance (pronounced PEE-awns) Basin don't have to be reassembled between wells. Instead, the drill can move horizontally and laterally to reposition. This speeds the process and cuts the cost of rig crews.
As with many so-called unconventional natural gas fields in the U.S. and around the world, simply drilling a well here won't produce much gas. Operators must fracture the underground rock or sand around the well to allow more gas to flow out.
"This is a very complex reservoir, one of the most complex I've worked on in my 33 years," said Jim Branch, project executive with Exxon Mobil Production Co.
From months to weeks
In the 1980s, frac jobs could take months. Now a complicated frac typically takes a couple of weeks. Exxon's Tolman developed a method to fracture a Piceance Basin well in three days, and he thinks he can compress it to 24 hours.
The key is to conduct every activity simultaneously. Everybody thought that was impossible until Tolman persuaded his colleagues to experiment.
While working on a natural gas well in La Barge, Wyo., in the 1980s, Tolman noticed something strange. Natural gas was flowing out of the well without pushing out or damaging the wire that operators had dropped into the well.
Years later, while descending an elevator at Exxon's corporate building in Houston, Tolman had an idea. Why not use this phenomenon to perform simultaneous functions on a well? That's exactly what he is doing at the site in Colorado.
Plenty of other natural gas producers operate wells in the Piceance Basin, but Exxon controls the sweet spot on land owned by the Bureau of Land Management.
The company has been producing small amounts of natural gas in the basin since the 1950s, with interests on 300,000 acres, holding enough gas to heat 50 million homes for a decade.
Exxon began a significant expansion here in 2007, after scientists developed drilling and fracing methods that could make the operations profitable. Exxon now operates seven rigs in the Piceance Basin and produces 100 million cubic feet a day. Project executive Branch said the company could eventually increase to 1 billion cubic feet a day.
Long-term outlook
The current lull in natural gas prices won't deter him.
"We're taking a long-term view," Branch said, repeating Exxon's mantra. He won't say whether the operations are profitable, with natural gas future prices trading below $4 per thousand cubic feet. Last summer, prices rose above $13.
Chief executive Tillerson said he's not specifically aiming to become more of a natural gas company than an oil company. Right now, Exxon's production is split about evenly between the two, and the company's strategy is to simply pursue the best projects each year.
"We don't have a deliberate strategy to change the oil-gas mix," Tillerson said during a news conference after the company's annual meeting earlier this year.
Analysts say a shift is evident and necessary.
Exxon's total natural gas sales have declined four out of the past five years, dropping 1.5 percent in 2008 to 10,812 million cubic feet per day. Production dropped 3 percent last year, although the company produced more natural gas than it discovered.
"By the time Exxon shifts, it will take three to five years before you see anything that's noticeable," said Oppenheimer & Co. analyst Fadel Gheit. "There is no instant gratification in anything they do."
The company has announced adding a number of unconventional resources to its books during the last few years, including fields in Germany, Eastern Europe, Canada and the Marcellus shale in the Northeast U.S.
"The future of unconventional shale gas, there's a pretty bright future," Tillerson said after the annual meeting. He said he's considering other fields as well, where Exxon can use its strategy of getting in cheaply, holding the resources for a long time and applying fresh technology.
Many of Exxon's new fields are shales, similar to the Barnett Shale in North Texas, where Exxon had a joint venture but sold out. The Piceance Basin isn't shale but sand. The company hasn't tried the new technology on shale reserves, and officials won't say where, exactly, they will try the process next.
"We haven't done it yet" on shales, Tolman said. "But I think there's a great opportunity."
Frac central
At the desert well site, workers wearing fireproof jumpsuits and hard hats in the summer heat have positioned the wire in the well. The frac water is flowing, and the pressure is building.
The frac specialists inside a (mercifully) air-conditioned trailer – some of them Halliburton employees working on a contract for Exxon – prepare to shoot electronic pulses from the wire.
The men watch colorful computer screens to monitor pressure created by pumping a mixture of sand, water and chemicals into the well. When the pressure is just right, they shoot the frac gun, then drop rubber balls into the well to plug the frac holes, and immediately repeat the process.
"Nineteen hundred until ball drop," says Ron Campbell, an Exxon workover superintendent manning one of the computers in the trailer. He's talking to the outdoor crews over a radio while staring at screens that monitor well pressure and tension on the wire lines.
Five other workers inside the trailer check computer monitors and scour instruction booklets. Scattered around the desk are bottles of water and Gatorade, a hard hat, a calculator and a half-eaten bag of Uncle Bob's Party Mix.
The red line on one of the screens rises. Over the radio, somebody says: "Shot is fired."
The red line wiggles as the rubber balls reach their holes and pressure inside the well builds.
"The frac is being a little bit fussy," Tolman says.
The men will fire the frac gun seven times today. While one gun is shooting the first well, they will load the second gun for well No. 2, back and forth, so that the men and the equipment are constantly working.
The natural gas will go through a treatment facility for cleaning, then into the U.S. pipeline system, bound for home cooktops, power plants and chemical facilities across the nation.
Most energy experts agree that demand for natural gas will surely rise if a bill to cut greenhouse gas emissions becomes law. The bill passed the House and awaits consideration by the Senate.
Renewable fuel sources can serve only a sliver of U.S. demand. Until more wind farms and solar arrays can be installed, Americans would have to rely on natural gas to comply with the new regulations. Natural gas emits less of the greenhouse gases thought to cause climate change than coal.
And, thanks to new drilling technologies, the U.S. has plenty of natural gas to meet the rules. According to the Energy Information Association, proved U.S. natural gas reserves in 2007, the most recent data, have risen by one-third to 237,726 billion cubic feet since 2002, just as the new techniques were becoming popular.
In fact, most experts agree that new technology, such as the Exxon process, offers the only hope of immediately meeting the greenhouse gas emissions goals outlined in the bill.
esouder@dallasnews.com
http://www.dallasnews.com/sharedcontent/dws/bus/stories/DN-exxon_26bus.ART.State.Edition1.3cf4b5d.html
RIFLE, Colo. – Dozens of workers mill around a jumble of pipes and whirring equipment surrounding 10 natural gas wells operated by Exxon Mobil Corp.
At this well site in the desert, 80 miles west of the Rocky Mountains tourism hive, the men load cranes, operate pumps and monitor little red lines on computer screens. The work must happen simultaneously, in a carefully orchestrated ballet, to keep the well costs low – and profit high enough – to be worth the effort of the country's largest oil company.
"We're about 15 minutes away from a new frac being born," Randy Tolman, Exxon's project coordinator for the Piceance Basin, shouts over the noise. He invented this faster method of fracturing, or "fracing," the underground layers of rock and sand to unlock natural gas.
Exxon aims to export the new process to the unconventional natural gas reserves it is accumulating around the world. Drilling for more natural gas could make Exxon a lot of money as Americans demand cleaner fuel because natural gas doesn't emit as much pollution or greenhouse gases as oil and coal when burned.
"It's the bridge fuel," said Amy Jaffe, associate director of Rice University's energy program, adding: "It's going to be a 20-year bridge."
Exxon forecasts that natural gas demand will rise 50 percent by 2030 and outstrip demand for coal.
"Clearly, we anticipate that natural gas will grow much faster than oil or coal. So we see a pretty healthy demand out there in the future for natural gas globally, but even here in North America," chief executive Rex Tillerson said during an analyst meeting earlier this year.
At the gas well site in the desert, Exxon has drilled 10 holes, five of which already produce natural gas. The company's rigs in the Piceance (pronounced PEE-awns) Basin don't have to be reassembled between wells. Instead, the drill can move horizontally and laterally to reposition. This speeds the process and cuts the cost of rig crews.
As with many so-called unconventional natural gas fields in the U.S. and around the world, simply drilling a well here won't produce much gas. Operators must fracture the underground rock or sand around the well to allow more gas to flow out.
"This is a very complex reservoir, one of the most complex I've worked on in my 33 years," said Jim Branch, project executive with Exxon Mobil Production Co.
From months to weeks
In the 1980s, frac jobs could take months. Now a complicated frac typically takes a couple of weeks. Exxon's Tolman developed a method to fracture a Piceance Basin well in three days, and he thinks he can compress it to 24 hours.
The key is to conduct every activity simultaneously. Everybody thought that was impossible until Tolman persuaded his colleagues to experiment.
While working on a natural gas well in La Barge, Wyo., in the 1980s, Tolman noticed something strange. Natural gas was flowing out of the well without pushing out or damaging the wire that operators had dropped into the well.
Years later, while descending an elevator at Exxon's corporate building in Houston, Tolman had an idea. Why not use this phenomenon to perform simultaneous functions on a well? That's exactly what he is doing at the site in Colorado.
Plenty of other natural gas producers operate wells in the Piceance Basin, but Exxon controls the sweet spot on land owned by the Bureau of Land Management.
The company has been producing small amounts of natural gas in the basin since the 1950s, with interests on 300,000 acres, holding enough gas to heat 50 million homes for a decade.
Exxon began a significant expansion here in 2007, after scientists developed drilling and fracing methods that could make the operations profitable. Exxon now operates seven rigs in the Piceance Basin and produces 100 million cubic feet a day. Project executive Branch said the company could eventually increase to 1 billion cubic feet a day.
Long-term outlook
The current lull in natural gas prices won't deter him.
"We're taking a long-term view," Branch said, repeating Exxon's mantra. He won't say whether the operations are profitable, with natural gas future prices trading below $4 per thousand cubic feet. Last summer, prices rose above $13.
Chief executive Tillerson said he's not specifically aiming to become more of a natural gas company than an oil company. Right now, Exxon's production is split about evenly between the two, and the company's strategy is to simply pursue the best projects each year.
"We don't have a deliberate strategy to change the oil-gas mix," Tillerson said during a news conference after the company's annual meeting earlier this year.
Analysts say a shift is evident and necessary.
Exxon's total natural gas sales have declined four out of the past five years, dropping 1.5 percent in 2008 to 10,812 million cubic feet per day. Production dropped 3 percent last year, although the company produced more natural gas than it discovered.
"By the time Exxon shifts, it will take three to five years before you see anything that's noticeable," said Oppenheimer & Co. analyst Fadel Gheit. "There is no instant gratification in anything they do."
The company has announced adding a number of unconventional resources to its books during the last few years, including fields in Germany, Eastern Europe, Canada and the Marcellus shale in the Northeast U.S.
"The future of unconventional shale gas, there's a pretty bright future," Tillerson said after the annual meeting. He said he's considering other fields as well, where Exxon can use its strategy of getting in cheaply, holding the resources for a long time and applying fresh technology.
Many of Exxon's new fields are shales, similar to the Barnett Shale in North Texas, where Exxon had a joint venture but sold out. The Piceance Basin isn't shale but sand. The company hasn't tried the new technology on shale reserves, and officials won't say where, exactly, they will try the process next.
"We haven't done it yet" on shales, Tolman said. "But I think there's a great opportunity."
Frac central
At the desert well site, workers wearing fireproof jumpsuits and hard hats in the summer heat have positioned the wire in the well. The frac water is flowing, and the pressure is building.
The frac specialists inside a (mercifully) air-conditioned trailer – some of them Halliburton employees working on a contract for Exxon – prepare to shoot electronic pulses from the wire.
The men watch colorful computer screens to monitor pressure created by pumping a mixture of sand, water and chemicals into the well. When the pressure is just right, they shoot the frac gun, then drop rubber balls into the well to plug the frac holes, and immediately repeat the process.
"Nineteen hundred until ball drop," says Ron Campbell, an Exxon workover superintendent manning one of the computers in the trailer. He's talking to the outdoor crews over a radio while staring at screens that monitor well pressure and tension on the wire lines.
Five other workers inside the trailer check computer monitors and scour instruction booklets. Scattered around the desk are bottles of water and Gatorade, a hard hat, a calculator and a half-eaten bag of Uncle Bob's Party Mix.
The red line on one of the screens rises. Over the radio, somebody says: "Shot is fired."
The red line wiggles as the rubber balls reach their holes and pressure inside the well builds.
"The frac is being a little bit fussy," Tolman says.
The men will fire the frac gun seven times today. While one gun is shooting the first well, they will load the second gun for well No. 2, back and forth, so that the men and the equipment are constantly working.
The natural gas will go through a treatment facility for cleaning, then into the U.S. pipeline system, bound for home cooktops, power plants and chemical facilities across the nation.
Most energy experts agree that demand for natural gas will surely rise if a bill to cut greenhouse gas emissions becomes law. The bill passed the House and awaits consideration by the Senate.
Renewable fuel sources can serve only a sliver of U.S. demand. Until more wind farms and solar arrays can be installed, Americans would have to rely on natural gas to comply with the new regulations. Natural gas emits less of the greenhouse gases thought to cause climate change than coal.
And, thanks to new drilling technologies, the U.S. has plenty of natural gas to meet the rules. According to the Energy Information Association, proved U.S. natural gas reserves in 2007, the most recent data, have risen by one-third to 237,726 billion cubic feet since 2002, just as the new techniques were becoming popular.
In fact, most experts agree that new technology, such as the Exxon process, offers the only hope of immediately meeting the greenhouse gas emissions goals outlined in the bill.
Saturday, July 25, 2009
Natural Gas Rig Count Up 10 Week Ending July 24, 2009
NEW YORK, July 24 (Reuters) - The number of rigs drilling for natural gas in the United States rose 10 this week to 675 after sinking last week to its lowest level in more than seven years, according to a report on Friday by oil services firm Baker Hughes in Houston.
U.S. natural gas drilling rigs have been in a mostly steady decline since peaking above 1,600 in September, and now stand at 880 rigs, or 57 percent, below the same week last year.
Last week, the natural gas rig count dipped to 665, its lowest level since May 3, 2002, when there were 640 gas rigs operating.
Tighter access to credit and a 70 percent slide in natural gas prices to about $3.50 per mmBtu after peaking above $13 last July have forced many producers to scale back drilling operations.
But while the steep decline in gas drilling this year has started to slow production and tighten supplies, most traders agreed it has not been enough yet to offset recession-related cuts in industrial demand and slight gains in imports of LNG.
The U.S. Energy Information Administration estimates that domestic gas production fell for a fourth straight month in June, with output dropping below the same year-ago month for the first time this year. (Reporting by Joe Silha; Editing by Marguerita Choy)
U.S. natural gas drilling rigs have been in a mostly steady decline since peaking above 1,600 in September, and now stand at 880 rigs, or 57 percent, below the same week last year.
Last week, the natural gas rig count dipped to 665, its lowest level since May 3, 2002, when there were 640 gas rigs operating.
Tighter access to credit and a 70 percent slide in natural gas prices to about $3.50 per mmBtu after peaking above $13 last July have forced many producers to scale back drilling operations.
But while the steep decline in gas drilling this year has started to slow production and tighten supplies, most traders agreed it has not been enough yet to offset recession-related cuts in industrial demand and slight gains in imports of LNG.
The U.S. Energy Information Administration estimates that domestic gas production fell for a fourth straight month in June, with output dropping below the same year-ago month for the first time this year. (Reporting by Joe Silha; Editing by Marguerita Choy)
Friday, July 24, 2009
Rocky Mountain Natural Gas Lowest in USA
http://www.cattlenetwork.com/Content.asp?ContentID=332905
Natural Gas Outlook: Prices Rise, Storage Above 5-Year Average
Price increases at all market locations during the report week were likely a response to increased cooling demand as warm temperatures prevailed across the lower 48 States. With a mean temperature in the 80s during the report week, the price at Florida’s sole gas trading location rose 47 cents to $4.24 per MMBtu. The Florida Gas Transmission Citygate location is the only place in the country with a price above $4. Elsewhere, average regional price increases ranged from 11 cents in South Texas to 32 cents in the Rockies. Most average regional price increases were between 15 and 20 cents. However, warmer weather was not the only factor influencing prices in all regions. For example, Louisiana posted some of the most moderate price increases, despite average temperatures in the 80s in the Gulf Coast region. The average price in Louisiana increased 11 cents to $3.33 per MMBtu. Abundance of working gas in storage in the region tempered price increases.
Despite relatively large increases, prices in the Rocky Mountains are the lowest in the country. Rocky Mountain prices increased an average of 32 cents to $2.98 per MMBtu, despite mild weather in the region. The 8 of the 12 Rockies trading locations that closed below $3 per MMBtu on July 15 were the only places in the country to do so. In fact, all trading locations in the Rockies fell below $3 during the report week, as maintenance on the Rockies Express Pipeline caused some natural gas to be stranded. Prices bounced back at the end of the week as a result of warmer weather, however, with temperatures above 90 degrees in Salt Lake City, Utah. Additionally, Rockies prices have fallen from an average of $4.35 per MMBtu since the beginning of 2009, although the difference between the Rockies and Henry Hub prices has tightened as the pipeline infrastructure has improved.
Though price gains this week reversed losses from the previous week, prices in all trading locations are still relatively low. Year-to-date, prices at the Henry Hub have fallen 40 percent from $5.63 per MMBtu. The current Henry Hub price of $3.37 per MMBtu has declined 70 percent from the year-ago closing price of $11.15 per MMBtu. The WTI crude oil contract has similarly declined, falling 52 percent from the closing price of $129.43 per barrel 1 year ago. Price declines in the past year are likely the result of the declining economy, reduced demand, and robust inventories. Additionally, the Baker Hughes natural gas rotary rig count has fallen by 47 percent to 672 from levels of 1,267 at the beginning of the year. Changes in the rig count generally lag changes in price by at least several weeks. (See Other Market Trends).
Unlike spot prices, futures prices fell slightly at the New York Mercantile Exchange. The August 2009 contract fell to $3.283 per MMBtu, from $3.353 per MMBtu. The contract declined in price 4 out of the 6 trading days in the reference period. Overall, the losses during the week reversed mid-week gains, when the contract rose 6 cents on July 9 and 17 cents on July 14. During its tenure as the near month contract, the August 2009 contract has lost 66 cents, or nearly 17 percent of its value. Since the beginning of the year, the August contract has fallen 49 percent, from $6.400. The 12-month strip (the average of prices for the August 2009 through July 2010 contracts) fell from $4.850 to $4.755, a decline of almost 10 cents, or about 2 percent. Declines in individual contract prices ranged from 2.3 cents (October 2009) to 13 cents (March 2010). The futures prices likely reflect expectations of robust storage inventories in the coming months.
Storage
Working gas in storage increased to 2,886 Bcf as of Friday, July 10, 2009, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). This year’s implied net injection of 90 Bcf exceeded the 5-year (2004-2008) average injection of 88 Bcf, but fell short of last year’s injection of 102 Bcf for the same week. Natural gas in storage is now 25.6 percent above inventories of 2,297 Bcf 1 year ago, and 18.7 percent above the 5-year average of 2,432 Bcf. Natural gas in storage is now at its highest level for any week in the month of July since collection of weekly storage data began in 1994. Levels for the Producing region and the West region are also at all-time highs for July. Regionally, this week the East region injected 62 Bcf, the West region injected 9 Bcf, and the Producing region injected 19 Bcf. For the end of the injection season, EIA’s Short-Term Energy Outlook is predicting inventories of 3,670 for the month of October.
The above-average storage injection partly resulted from slightly cooler-than-normal temperatures during the report week (see Temperature Maps and Data). The average temperature for the United States was 72.6 degrees during the report week, compared with 74.4 degrees for both the same week last year and the normal temperature. However, temperatures in the West South Central Census Division, which includes Texas, Louisiana, Arkansas, and Oklahoma, averaged 84.3 degrees, which was 2.1 degrees higher than the normal temperature and 3.6 degrees more than the previous year. This region was the only region with temperatures warmer than normal and warmer than last year.
Other Market Trends
EIA releases Country Analysis Brief on Canada. The Energy Information Administration (EIA) on July 9 issued a Country Analysis Brief describing the energy profile of Canada. Canada is the largest source of U.S. energy imports, with almost all of Canada’s exports going to the United States. According to the County Analysis Brief, Canada produced 6.6 trillion cubic feet (Tcf) of natural gas in 2007 and consumed 3.3 Tcf. As of January 2009, Canada had 57.9 Tcf of reserves. Canada’s natural gas production is concentrated in the Western Canada Sedimentary Basin (WCSB), particularly in Alberta. Many analysts predict that conventional natural gas production in the area has likely peaked, and future production will increasingly come from coalbed methane and shale in the WCSB. Natural gas located in Arctic areas will also likely play an increasingly important role in Canada’s natural gas production, as the Mackenzie Delta in the Northwest Territories holds between 5 and 6 Tcf of recoverable natural gas. The Mackenzie Valley pipeline, a 760-mile project planned for the area, would transport gas from the Arctic region to a connection with the existing transportation system in Northern Alberta. Canada is also looking to liquefied natural gas (LNG) gas to deal with possible future supply shortfalls in the future—several regasification terminals mostly in the east, as well as one liquefaction terminal in the west, have been proposed for Canada. The full index of Country Analysis Briefs can be found at http://www.eia.doe.gov/emeu/cabs/index.html.
MMS Reports Results of Central Gulf of Mexico Sale 208. The Minerals Management Service (MMS) announced on July 10 that the Central Gulf of Mexico Oil and Gas Lease Sale 208 attracted a total of $690 million in high bids and awarded 328 leases to the successful high bidders. MMS received 476 bids from 70 companies, with the sum of all high bids received totaling $703 million. MMS evaluates each high bid to ensure the public receives fair market value before awarding a lease. MMS rejected high bids totaling nearly $13 million on 19 tracts as a result of their evaluation process. Shell Gulf of Mexico Inc. had the highest number of accepted high bids, 39, totaling almost $154 million. Shell also submitted the highest accepted bid of approximately $66 million.
Natural gas rotary rig count continues to decline. Baker Hughes Incorporated reported that the natural gas rotary rig count was 672 as of July 10, representing a 16-rig decline from the previous week. Rigs are at their lowest level since May 10, 2002. Natural gas rigs have fallen 58 percent from their highest-recorded level of 1,606, reached in late summer 2008. However, the decline appears to be flattening. Rigs recently posted an increase on June 19 and July 2. For the first 4 weeks of 2009, the average change in rigs was a decline of 40.5. For the previous 4 weeks (including the most recent data), the average change in rigs was a decline of 3.25. Additionally, horizontal rigs (both oil and natural gas) have outnumbered vertical rigs (also both oil and natural gas) for the eighth consecutive week. In March, the level of horizontal rigs overtook the number of vertical rigs for the first time since Baker Hughes began publishing data by drilling type. On July 10, horizontal rigs totaled 390 as of July 10, a decline of 6 from the previous week. Over the same period, the vertical rig count fell by 10 to 361.
Natural Gas Transportation Update
Texas Gas Transmission, LLC on July 10 revealed that it had found pipeline anomalies in the newly-constructed Fayetteville Lateral in Arkansas and Greenville Lateral in Mississippi. The pipeline company said that testing of pipe samples may require up to 2 months to complete. In the interim, pipeline operating capacities will be significantly reduced. Repairs of the laterals, which serve growing production from the Fayetteville Shale, will occur over several months after the results from testing are received. According to Texas Gas, pipeline work on various segments of the laterals could continue for up to 5 months. Although Texas Gas will attempt to maximize flows on its laterals during this time, shippers should anticipate capacity limitations. Texas gas will release details of its remediation schedule as they become available.
Sea Robin Pipeline Company, LLC on Tuesday, July 14, said it was beginning to repair damage to its pipeline in the western Gulf of Mexico. The repairs are part of the pipeline’s continuing efforts to restore infrastructure damaged last year during Hurricane Ike. Repairs to the south end of Sea Robin’s 30-inch diameter segment from East Cameron 334 to East Cameron 195 are expected to be complete this week, after which Sea Robin will initiate hydrotesting of the pipeline. Full operations of the pipeline are expected to commence by July 23.
Southern Natural Gas Company (SNG) on Wednesday, July 15, revealed that it will close a portion of its pipeline in the central Gulf of Mexico for up to 6 days. SNG’s West Delta 12 receipt point will be shut in as the pipeline abandons its 16-inch diameter Mississippi Canyon 268 Line. The closure will begin on July 19 or July 20, according to SNG. The pipeline also announced that it will begin about 3 weeks of maintenance on July 17 at the Mississippi Canyon 194 platform. This work will require the shut-in of two Mississippi Canyon meters and the Romere Pass meter.
Natural Gas Outlook: Prices Rise, Storage Above 5-Year Average
Price increases at all market locations during the report week were likely a response to increased cooling demand as warm temperatures prevailed across the lower 48 States. With a mean temperature in the 80s during the report week, the price at Florida’s sole gas trading location rose 47 cents to $4.24 per MMBtu. The Florida Gas Transmission Citygate location is the only place in the country with a price above $4. Elsewhere, average regional price increases ranged from 11 cents in South Texas to 32 cents in the Rockies. Most average regional price increases were between 15 and 20 cents. However, warmer weather was not the only factor influencing prices in all regions. For example, Louisiana posted some of the most moderate price increases, despite average temperatures in the 80s in the Gulf Coast region. The average price in Louisiana increased 11 cents to $3.33 per MMBtu. Abundance of working gas in storage in the region tempered price increases.
Despite relatively large increases, prices in the Rocky Mountains are the lowest in the country. Rocky Mountain prices increased an average of 32 cents to $2.98 per MMBtu, despite mild weather in the region. The 8 of the 12 Rockies trading locations that closed below $3 per MMBtu on July 15 were the only places in the country to do so. In fact, all trading locations in the Rockies fell below $3 during the report week, as maintenance on the Rockies Express Pipeline caused some natural gas to be stranded. Prices bounced back at the end of the week as a result of warmer weather, however, with temperatures above 90 degrees in Salt Lake City, Utah. Additionally, Rockies prices have fallen from an average of $4.35 per MMBtu since the beginning of 2009, although the difference between the Rockies and Henry Hub prices has tightened as the pipeline infrastructure has improved.
Though price gains this week reversed losses from the previous week, prices in all trading locations are still relatively low. Year-to-date, prices at the Henry Hub have fallen 40 percent from $5.63 per MMBtu. The current Henry Hub price of $3.37 per MMBtu has declined 70 percent from the year-ago closing price of $11.15 per MMBtu. The WTI crude oil contract has similarly declined, falling 52 percent from the closing price of $129.43 per barrel 1 year ago. Price declines in the past year are likely the result of the declining economy, reduced demand, and robust inventories. Additionally, the Baker Hughes natural gas rotary rig count has fallen by 47 percent to 672 from levels of 1,267 at the beginning of the year. Changes in the rig count generally lag changes in price by at least several weeks. (See Other Market Trends).
Unlike spot prices, futures prices fell slightly at the New York Mercantile Exchange. The August 2009 contract fell to $3.283 per MMBtu, from $3.353 per MMBtu. The contract declined in price 4 out of the 6 trading days in the reference period. Overall, the losses during the week reversed mid-week gains, when the contract rose 6 cents on July 9 and 17 cents on July 14. During its tenure as the near month contract, the August 2009 contract has lost 66 cents, or nearly 17 percent of its value. Since the beginning of the year, the August contract has fallen 49 percent, from $6.400. The 12-month strip (the average of prices for the August 2009 through July 2010 contracts) fell from $4.850 to $4.755, a decline of almost 10 cents, or about 2 percent. Declines in individual contract prices ranged from 2.3 cents (October 2009) to 13 cents (March 2010). The futures prices likely reflect expectations of robust storage inventories in the coming months.
Storage
Working gas in storage increased to 2,886 Bcf as of Friday, July 10, 2009, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). This year’s implied net injection of 90 Bcf exceeded the 5-year (2004-2008) average injection of 88 Bcf, but fell short of last year’s injection of 102 Bcf for the same week. Natural gas in storage is now 25.6 percent above inventories of 2,297 Bcf 1 year ago, and 18.7 percent above the 5-year average of 2,432 Bcf. Natural gas in storage is now at its highest level for any week in the month of July since collection of weekly storage data began in 1994. Levels for the Producing region and the West region are also at all-time highs for July. Regionally, this week the East region injected 62 Bcf, the West region injected 9 Bcf, and the Producing region injected 19 Bcf. For the end of the injection season, EIA’s Short-Term Energy Outlook is predicting inventories of 3,670 for the month of October.
The above-average storage injection partly resulted from slightly cooler-than-normal temperatures during the report week (see Temperature Maps and Data). The average temperature for the United States was 72.6 degrees during the report week, compared with 74.4 degrees for both the same week last year and the normal temperature. However, temperatures in the West South Central Census Division, which includes Texas, Louisiana, Arkansas, and Oklahoma, averaged 84.3 degrees, which was 2.1 degrees higher than the normal temperature and 3.6 degrees more than the previous year. This region was the only region with temperatures warmer than normal and warmer than last year.
Other Market Trends
EIA releases Country Analysis Brief on Canada. The Energy Information Administration (EIA) on July 9 issued a Country Analysis Brief describing the energy profile of Canada. Canada is the largest source of U.S. energy imports, with almost all of Canada’s exports going to the United States. According to the County Analysis Brief, Canada produced 6.6 trillion cubic feet (Tcf) of natural gas in 2007 and consumed 3.3 Tcf. As of January 2009, Canada had 57.9 Tcf of reserves. Canada’s natural gas production is concentrated in the Western Canada Sedimentary Basin (WCSB), particularly in Alberta. Many analysts predict that conventional natural gas production in the area has likely peaked, and future production will increasingly come from coalbed methane and shale in the WCSB. Natural gas located in Arctic areas will also likely play an increasingly important role in Canada’s natural gas production, as the Mackenzie Delta in the Northwest Territories holds between 5 and 6 Tcf of recoverable natural gas. The Mackenzie Valley pipeline, a 760-mile project planned for the area, would transport gas from the Arctic region to a connection with the existing transportation system in Northern Alberta. Canada is also looking to liquefied natural gas (LNG) gas to deal with possible future supply shortfalls in the future—several regasification terminals mostly in the east, as well as one liquefaction terminal in the west, have been proposed for Canada. The full index of Country Analysis Briefs can be found at http://www.eia.doe.gov/emeu/cabs/index.html.
MMS Reports Results of Central Gulf of Mexico Sale 208. The Minerals Management Service (MMS) announced on July 10 that the Central Gulf of Mexico Oil and Gas Lease Sale 208 attracted a total of $690 million in high bids and awarded 328 leases to the successful high bidders. MMS received 476 bids from 70 companies, with the sum of all high bids received totaling $703 million. MMS evaluates each high bid to ensure the public receives fair market value before awarding a lease. MMS rejected high bids totaling nearly $13 million on 19 tracts as a result of their evaluation process. Shell Gulf of Mexico Inc. had the highest number of accepted high bids, 39, totaling almost $154 million. Shell also submitted the highest accepted bid of approximately $66 million.
Natural gas rotary rig count continues to decline. Baker Hughes Incorporated reported that the natural gas rotary rig count was 672 as of July 10, representing a 16-rig decline from the previous week. Rigs are at their lowest level since May 10, 2002. Natural gas rigs have fallen 58 percent from their highest-recorded level of 1,606, reached in late summer 2008. However, the decline appears to be flattening. Rigs recently posted an increase on June 19 and July 2. For the first 4 weeks of 2009, the average change in rigs was a decline of 40.5. For the previous 4 weeks (including the most recent data), the average change in rigs was a decline of 3.25. Additionally, horizontal rigs (both oil and natural gas) have outnumbered vertical rigs (also both oil and natural gas) for the eighth consecutive week. In March, the level of horizontal rigs overtook the number of vertical rigs for the first time since Baker Hughes began publishing data by drilling type. On July 10, horizontal rigs totaled 390 as of July 10, a decline of 6 from the previous week. Over the same period, the vertical rig count fell by 10 to 361.
Natural Gas Transportation Update
Texas Gas Transmission, LLC on July 10 revealed that it had found pipeline anomalies in the newly-constructed Fayetteville Lateral in Arkansas and Greenville Lateral in Mississippi. The pipeline company said that testing of pipe samples may require up to 2 months to complete. In the interim, pipeline operating capacities will be significantly reduced. Repairs of the laterals, which serve growing production from the Fayetteville Shale, will occur over several months after the results from testing are received. According to Texas Gas, pipeline work on various segments of the laterals could continue for up to 5 months. Although Texas Gas will attempt to maximize flows on its laterals during this time, shippers should anticipate capacity limitations. Texas gas will release details of its remediation schedule as they become available.
Sea Robin Pipeline Company, LLC on Tuesday, July 14, said it was beginning to repair damage to its pipeline in the western Gulf of Mexico. The repairs are part of the pipeline’s continuing efforts to restore infrastructure damaged last year during Hurricane Ike. Repairs to the south end of Sea Robin’s 30-inch diameter segment from East Cameron 334 to East Cameron 195 are expected to be complete this week, after which Sea Robin will initiate hydrotesting of the pipeline. Full operations of the pipeline are expected to commence by July 23.
Southern Natural Gas Company (SNG) on Wednesday, July 15, revealed that it will close a portion of its pipeline in the central Gulf of Mexico for up to 6 days. SNG’s West Delta 12 receipt point will be shut in as the pipeline abandons its 16-inch diameter Mississippi Canyon 268 Line. The closure will begin on July 19 or July 20, according to SNG. The pipeline also announced that it will begin about 3 weeks of maintenance on July 17 at the Mississippi Canyon 194 platform. This work will require the shut-in of two Mississippi Canyon meters and the Romere Pass meter.
Thursday, July 23, 2009
Occidental Petroleum Find Natural Gas in California
July 22 (Bloomberg) -- Occidental Petroleum Corp., the biggest oil producer in Texas, said its discovery of a natural- gas and oil field in California holding the equivalent of as much as 250 million barrels of crude may be the state’s biggest in 35 years.
The field in Kern County is 80 percent-owned by Occidental, the Los Angeles-based company said today in a statement. The find has the potential to boost Occidental’s California reserves by 28 percent.
Chief Executive Officer Ray Irani said in an interview last month that the company plans to drill 20 exploratory wells this year in California to tap prospects near Long Beach and in other parts of the state that may hold hundreds of millions of barrels of crude.
“We believe this to be the largest new oil and gas discovery made in California in more than 35 years,” Irani said in today’s statement.
Occidental rose 95 cents, or 1.4 percent, to $70.94 at 4:55 p.m. in after-hours trading. The stock has risen 18 percent this year, outperforming its largest U.S. rivals, Exxon Mobil Corp., Chevron Corp. and ConocoPhillips, which have declined.
Reserves Boost
Occidental estimated the field holds the equivalent of 150 million to 250 million barrels of crude, based on results of six wells drilled in the formation. At the high end of that range, the company’s 80 percent stake would swell its California reserves to the equivalent of 908 million barrels of oil.
More work is required to define the extent of the field, Occidental said. About two-thirds of the hydrocarbons are in the form of natural gas. Kern County, home to the city of Bakersfield, has been a petroleum-producing region since the 1860s, when tar was mined to make kerosene and asphalt, according to the San Joaquin Geological Society.
California is the third-biggest oil-producing U.S. state, behind Texas and Alaska, Energy Department figures showed. California held 3.3 billion barrels of proved reserves at the end of 2007, or about 15 percent of the nation’s total.
Land Grab
Occidental began acquiring leaseholds on privately held California land five years ago with a view to tapping reserves that were overlooked or dismissed by rival companies three decades ago, Irani said in the June 24 interview. Those leases encompass 1.1 million acres, an area three times the size of New York City.
New methods for reading seismic data and other technological advances have allowed the company’s engineers to detect petroleum, Chief Financial Officer Stephen Chazen said during the same interview.
Occidental’s California drilling program is targeting fields with oil and natural-gas reserves equivalent to at least 150 million barrels of crude each, Chazen said last month. That would be about one-third the size of Chevron’s deepwater Tahiti field in the Gulf of Mexico, which began production in May.
Irani, 74, raised production and reserves in each of the past three years. Exxon Mobil, Chevron and ConocoPhillips all had declines in two or more of those years.
To contact the reporter on this story: Joe Carroll in Chicago at jcarroll8@bloomberg.net.
The field in Kern County is 80 percent-owned by Occidental, the Los Angeles-based company said today in a statement. The find has the potential to boost Occidental’s California reserves by 28 percent.
Chief Executive Officer Ray Irani said in an interview last month that the company plans to drill 20 exploratory wells this year in California to tap prospects near Long Beach and in other parts of the state that may hold hundreds of millions of barrels of crude.
“We believe this to be the largest new oil and gas discovery made in California in more than 35 years,” Irani said in today’s statement.
Occidental rose 95 cents, or 1.4 percent, to $70.94 at 4:55 p.m. in after-hours trading. The stock has risen 18 percent this year, outperforming its largest U.S. rivals, Exxon Mobil Corp., Chevron Corp. and ConocoPhillips, which have declined.
Reserves Boost
Occidental estimated the field holds the equivalent of 150 million to 250 million barrels of crude, based on results of six wells drilled in the formation. At the high end of that range, the company’s 80 percent stake would swell its California reserves to the equivalent of 908 million barrels of oil.
More work is required to define the extent of the field, Occidental said. About two-thirds of the hydrocarbons are in the form of natural gas. Kern County, home to the city of Bakersfield, has been a petroleum-producing region since the 1860s, when tar was mined to make kerosene and asphalt, according to the San Joaquin Geological Society.
California is the third-biggest oil-producing U.S. state, behind Texas and Alaska, Energy Department figures showed. California held 3.3 billion barrels of proved reserves at the end of 2007, or about 15 percent of the nation’s total.
Land Grab
Occidental began acquiring leaseholds on privately held California land five years ago with a view to tapping reserves that were overlooked or dismissed by rival companies three decades ago, Irani said in the June 24 interview. Those leases encompass 1.1 million acres, an area three times the size of New York City.
New methods for reading seismic data and other technological advances have allowed the company’s engineers to detect petroleum, Chief Financial Officer Stephen Chazen said during the same interview.
Occidental’s California drilling program is targeting fields with oil and natural-gas reserves equivalent to at least 150 million barrels of crude each, Chazen said last month. That would be about one-third the size of Chevron’s deepwater Tahiti field in the Gulf of Mexico, which began production in May.
Irani, 74, raised production and reserves in each of the past three years. Exxon Mobil, Chevron and ConocoPhillips all had declines in two or more of those years.
To contact the reporter on this story: Joe Carroll in Chicago at jcarroll8@bloomberg.net.
Wednesday, July 22, 2009
U.S. House Reps Vote $150 MM for Natural Gas Vehicles
David Shepardson / Detroit News Washington Bureau
Washington -- The House overwhelmingly approved a $150 million program to research natural-gas powered vehicles.
By a vote of 363 to 35, the House passed the bill that authorizes the Energy Department to conduct a five-year program of natural gas vehicle research, development and demonstration, authorizing $30 million annually starting in the 2010 budget year.
The research program is to aid "the continued improvement and development of new, cleaner, more efficient light-duty, medium-duty, and heavy-duty natural gas vehicle engines." The bill also seeks to improve the reliability and efficiency of natural gas fueling station infrastructure and boost the use of natural gas engines in hybrid vehicles.
The bill was written by Rep. John Sullivan, R-Okla.
"The vehicle fleet of the future will include a diverse range of fuels and vehicle technologies," said Rep. Bart Gordon, D-Tenn., chairman of the House Science and Technology Committee. "And since it is both cleaner than petroleum and domestically available, natural gas will likely play an important role in a more sustainable transportation sector."
Earlier this month, Senate leaders, joined by Texas oil billionaire T. Boone Pickens, unveiled a bill to jumpstart the production of vehicles that run on natural gas.
The legislation, dubbed the NAT-GAS bill, was introduced by Sen. Majority Leader Harry Reid, D-Nev., and Sens. Orrin Hatch, R-Utah and Robert Menendez, D-N.J. It would increase tax credits for buying a natural gas-powered vehicle from $5,000 to $12,500, boost grants to create additional natural gas filling stations and create grants for light- and heavy-duty natural gas engine development.
While there are about 10 million vehicles worldwide that run on natural gas, only about 142,000 of them are in the United States.
Automakers haven't shown much interest in building or selling natural gas vehicles in this country.
Honda Motor Co., whose Civic GX runs on compressed natural gas, is the only automaker that builds and sells a natural gas vehicle in the United States.
Honda moved production of the CNG Honda GX to Indiana from Ohio in May. But in the first nine months of the model year, it had sold only about 1,700 models in the United States
A similar bill was introduced in the House in April.
According to the California Energy Commission, greenhouse gas emissions from natural gas are 23 percent lower than diesel and 30 percent lower than gasoline. Natural gas produces virtually no particulate emissions, making it cleaner than diesel.
But unlike solar or wind power, natural gas is not a renewable source of energy and some environmentalists oppose expanding its use.
Municipal bus systems have used using compressed natural gas for decades. About 20 percent of public transit buses in the U.S. run on compressed natural gas.
dshepardson@detnews.com (202) 662-8735
http://www.detnews.com/article/20090721/AUTO01/907210404/1361/House-OKs-$150-million-natural-gas-car-program
Washington -- The House overwhelmingly approved a $150 million program to research natural-gas powered vehicles.
By a vote of 363 to 35, the House passed the bill that authorizes the Energy Department to conduct a five-year program of natural gas vehicle research, development and demonstration, authorizing $30 million annually starting in the 2010 budget year.
The research program is to aid "the continued improvement and development of new, cleaner, more efficient light-duty, medium-duty, and heavy-duty natural gas vehicle engines." The bill also seeks to improve the reliability and efficiency of natural gas fueling station infrastructure and boost the use of natural gas engines in hybrid vehicles.
The bill was written by Rep. John Sullivan, R-Okla.
"The vehicle fleet of the future will include a diverse range of fuels and vehicle technologies," said Rep. Bart Gordon, D-Tenn., chairman of the House Science and Technology Committee. "And since it is both cleaner than petroleum and domestically available, natural gas will likely play an important role in a more sustainable transportation sector."
Earlier this month, Senate leaders, joined by Texas oil billionaire T. Boone Pickens, unveiled a bill to jumpstart the production of vehicles that run on natural gas.
The legislation, dubbed the NAT-GAS bill, was introduced by Sen. Majority Leader Harry Reid, D-Nev., and Sens. Orrin Hatch, R-Utah and Robert Menendez, D-N.J. It would increase tax credits for buying a natural gas-powered vehicle from $5,000 to $12,500, boost grants to create additional natural gas filling stations and create grants for light- and heavy-duty natural gas engine development.
While there are about 10 million vehicles worldwide that run on natural gas, only about 142,000 of them are in the United States.
Automakers haven't shown much interest in building or selling natural gas vehicles in this country.
Honda Motor Co., whose Civic GX runs on compressed natural gas, is the only automaker that builds and sells a natural gas vehicle in the United States.
Honda moved production of the CNG Honda GX to Indiana from Ohio in May. But in the first nine months of the model year, it had sold only about 1,700 models in the United States
A similar bill was introduced in the House in April.
According to the California Energy Commission, greenhouse gas emissions from natural gas are 23 percent lower than diesel and 30 percent lower than gasoline. Natural gas produces virtually no particulate emissions, making it cleaner than diesel.
But unlike solar or wind power, natural gas is not a renewable source of energy and some environmentalists oppose expanding its use.
Municipal bus systems have used using compressed natural gas for decades. About 20 percent of public transit buses in the U.S. run on compressed natural gas.
dshepardson@detnews.com (202) 662-8735
http://www.detnews.com/article/20090721/AUTO01/907210404/1361/House-OKs-$150-million-natural-gas-car-program
Tuesday, July 21, 2009
Natural Gas Pricing News Today
By Christine Buurma
Of DOW JONES NEWSWIRES
NEW YORK -(Dow Jones)- Natural gas futures finished slightly higher Monday, supported by positive economic data and rising crude oil prices.
Natural gas for August delivery on the New York Mercantile Exchange settled 2 cents, or 0.55%, higher at $3.689 a million British thermal units after reaching a high of $3.774/MMBu in combined electronic and floor trade earlier in the day.
Some better-than-expected company earnings, a rise in a measure of economic activity and news that commercial lender CIT Group Inc. (CIT) struck a deal to avoid bankruptcy helped boost energy commodities Monday. Traders have been looking for signs of economic recovery that could point to a rebound in oil and gas demand.
Nymex light, sweet crude oil for August delivery settled 42 cents, or 0.66%, higher at $63.98. Natural gas can be used as a substitute for petroleum products in some power plants and heating systems.
"This market has been waiting for more earnings to see where things stand" in terms of the economic outlook, said Pax Saunders, an analyst with Houston-based energy advisory firm Gelber & Associates.
Toy maker Hasbro Inc. (HAS) reported Monday its second-quarter profit rose 5%, beating expectations. Oilfield services company Halliburton Co.'s (HAL) earnings fell, but the results surpassed analysts' forecasts.
The Conference Board, a non-profit group for business executives, said Monday its index of leading economic indicators rose 0.7% in June.
But mixed weather forecasts and abundant supplies continued to place some downward pressure on gas prices. Total gas in storage as of July 10 was 2.886 trillion cubic feet, 18.7% above the five-year average and 25.6% above last year's level.
Moderate temperatures in the major gas-consuming regions over the next two weeks were expected to limit cooling demand for natural gas. Unusually cool weather will continue in parts of the Great Lakes and Northeast into early August, said Jim Rouiller, a meteorologist with private forecaster Planalytics Inc., in a note to clients Tuesday.
"High temperatures will range from the low 70s to the low 80s across the Northeast and Great Lakes while upper 70s to mid 80s prevail across the Midwest and Mid-Atlantic," Rouiller wrote.
FUTURES SETTLEMENT NET CHANGE
Nymex Aug $3.689 +2.0c
Nymex Sep $3.838 +2.2c
Nymex Oct $4.045 +1.7c
CASH HUB RANGE PREVIOUS DAY
Henry Hub $3.36-$3.52 $3.33-$3.50
Transco 65 $3.46-$3.56 $3.65-$3.75
Tex East M3 $3.72-$3.79 $3.60-$3.77
Transco Z6 $3.76-$3.81 $3.65-$3.75
SoCal $3.45-$3.57 $3.36-$3.46
El Paso Perm $3.36-$3.46 $3.19-$3.33
El Paso SJ $3.37-$3.42 $3.17-$3.25
Waha $3.39-$3.46 $3.23-$3.34
Katy $3.33-$3.48 $3.31-$3.42
Of DOW JONES NEWSWIRES
NEW YORK -(Dow Jones)- Natural gas futures finished slightly higher Monday, supported by positive economic data and rising crude oil prices.
Natural gas for August delivery on the New York Mercantile Exchange settled 2 cents, or 0.55%, higher at $3.689 a million British thermal units after reaching a high of $3.774/MMBu in combined electronic and floor trade earlier in the day.
Some better-than-expected company earnings, a rise in a measure of economic activity and news that commercial lender CIT Group Inc. (CIT) struck a deal to avoid bankruptcy helped boost energy commodities Monday. Traders have been looking for signs of economic recovery that could point to a rebound in oil and gas demand.
Nymex light, sweet crude oil for August delivery settled 42 cents, or 0.66%, higher at $63.98. Natural gas can be used as a substitute for petroleum products in some power plants and heating systems.
"This market has been waiting for more earnings to see where things stand" in terms of the economic outlook, said Pax Saunders, an analyst with Houston-based energy advisory firm Gelber & Associates.
Toy maker Hasbro Inc. (HAS) reported Monday its second-quarter profit rose 5%, beating expectations. Oilfield services company Halliburton Co.'s (HAL) earnings fell, but the results surpassed analysts' forecasts.
The Conference Board, a non-profit group for business executives, said Monday its index of leading economic indicators rose 0.7% in June.
But mixed weather forecasts and abundant supplies continued to place some downward pressure on gas prices. Total gas in storage as of July 10 was 2.886 trillion cubic feet, 18.7% above the five-year average and 25.6% above last year's level.
Moderate temperatures in the major gas-consuming regions over the next two weeks were expected to limit cooling demand for natural gas. Unusually cool weather will continue in parts of the Great Lakes and Northeast into early August, said Jim Rouiller, a meteorologist with private forecaster Planalytics Inc., in a note to clients Tuesday.
"High temperatures will range from the low 70s to the low 80s across the Northeast and Great Lakes while upper 70s to mid 80s prevail across the Midwest and Mid-Atlantic," Rouiller wrote.
FUTURES SETTLEMENT NET CHANGE
Nymex Aug $3.689 +2.0c
Nymex Sep $3.838 +2.2c
Nymex Oct $4.045 +1.7c
CASH HUB RANGE PREVIOUS DAY
Henry Hub $3.36-$3.52 $3.33-$3.50
Transco 65 $3.46-$3.56 $3.65-$3.75
Tex East M3 $3.72-$3.79 $3.60-$3.77
Transco Z6 $3.76-$3.81 $3.65-$3.75
SoCal $3.45-$3.57 $3.36-$3.46
El Paso Perm $3.36-$3.46 $3.19-$3.33
El Paso SJ $3.37-$3.42 $3.17-$3.25
Waha $3.39-$3.46 $3.23-$3.34
Katy $3.33-$3.48 $3.31-$3.42
Monday, July 20, 2009
Natural Gas Storage Increase is EU Goal
BRUSSELS (AP) — The European Union called Thursday on member nations to ramp up natural gas storage and build more pipelines to cope with any future cutoff in energy supplies from Russia.
In January, thousands of homes went without heating and some power plants shut down when gas stopped flowing through pipelines from Russia due to a payment dispute with its neighbor Ukraine.
EU officials complained that Europeans were held hostage by the row and are seeking new routes and sources for energy — something that will take years to realize.
The EU executive says the 27-nation bloc could double gas storage by 2015. It said Romania — one of the bloc's poorest states — and Slovenia urgently need to build more storage because they depend so heavily on imports.
It is also calling for better energy connections between countries to help pump gas to where it is needed if supplies fall short.
EU Energy Commissioner Andris Piebalgs said the EU was ready to help fund some of this new infrastructure. He added, however, that the decisions need to be made by governments and that private companies also had to bear some of the costs.
The EU said euro1 trillion ($1.4 trillion) needs to be spent by 2030 to upgrade Europe's power generation and grid and euro150 billion ($211 billion) on gas networks, including pipelines from suppliers.
Under a proposed draft law, the European Commission called on EU nations to share information on their gas demand and supply.
It does not require them to pool supplies in times of trouble. Piebalgs said this would be an overreaction to the gas crisis and any sharing should be voluntary.
The EU Commission also said Europeans can play a part by using less natural gas for heating or cooking.
EU officials hold talks Friday with the Ukrainian and Russian state-owned gas producers who are asking for a multibillion dollar loan to help Ukraine pay its energy bills to Russia's Gazprom. The EU says any loan must be linked to promises not to interrupt Europe's supply again.
One quarter of the EU's energy comes from natural gas, 58 percent of it imported. Russia provides two-fifths of these gas imports, most of that passing through Ukraine. The EU's eight eastern European members depend on Russia for more than three quarters of their gas.
Other major gas suppliers are Norway, Libya and Algeria.
The EU expects gas imports to surge by 2020 as European wells run dry and power companies shift from burning coal to less polluting gas to try and curb greenhouse gas emissions.
http://www.latimes.com/business/nationworld/wire/sns-ap-eu-eu-energy,0,2298818.story
In January, thousands of homes went without heating and some power plants shut down when gas stopped flowing through pipelines from Russia due to a payment dispute with its neighbor Ukraine.
EU officials complained that Europeans were held hostage by the row and are seeking new routes and sources for energy — something that will take years to realize.
The EU executive says the 27-nation bloc could double gas storage by 2015. It said Romania — one of the bloc's poorest states — and Slovenia urgently need to build more storage because they depend so heavily on imports.
It is also calling for better energy connections between countries to help pump gas to where it is needed if supplies fall short.
EU Energy Commissioner Andris Piebalgs said the EU was ready to help fund some of this new infrastructure. He added, however, that the decisions need to be made by governments and that private companies also had to bear some of the costs.
The EU said euro1 trillion ($1.4 trillion) needs to be spent by 2030 to upgrade Europe's power generation and grid and euro150 billion ($211 billion) on gas networks, including pipelines from suppliers.
Under a proposed draft law, the European Commission called on EU nations to share information on their gas demand and supply.
It does not require them to pool supplies in times of trouble. Piebalgs said this would be an overreaction to the gas crisis and any sharing should be voluntary.
The EU Commission also said Europeans can play a part by using less natural gas for heating or cooking.
EU officials hold talks Friday with the Ukrainian and Russian state-owned gas producers who are asking for a multibillion dollar loan to help Ukraine pay its energy bills to Russia's Gazprom. The EU says any loan must be linked to promises not to interrupt Europe's supply again.
One quarter of the EU's energy comes from natural gas, 58 percent of it imported. Russia provides two-fifths of these gas imports, most of that passing through Ukraine. The EU's eight eastern European members depend on Russia for more than three quarters of their gas.
Other major gas suppliers are Norway, Libya and Algeria.
The EU expects gas imports to surge by 2020 as European wells run dry and power companies shift from burning coal to less polluting gas to try and curb greenhouse gas emissions.
http://www.latimes.com/business/nationworld/wire/sns-ap-eu-eu-energy,0,2298818.story
Sunday, July 19, 2009
Natural Gas Rig Count Down Again to 869
NEW YORK, July 17 (Reuters) - The number of rigs drilling for natural gas in the United States fell 7 this week to 665, the lowest level in more than seven years, according to a report on Friday by oil services firm Baker Hughes in Houston.
U.S. natural gas drilling rigs have been in a mostly steady decline since peaking above 1,600 in September, and now stand at 869 rigs, or 57 percent, below the same week last year.
It is the lowest natural gas rig count since May 3, 2002, when there were 640 rigs operating.
Sources noted the gas rig count decline seemed to be slowing since first falling below the 700 mark five weeks ago.
Tighter access to credit and a 70 percent slide in natural gas prices to about $3.50 per mmBtu after peaking above $13 last July have forced many producers to scale back drilling operations.
But with the natural gas drilling rig count now firmly entrenched below 700, and monthly production down four straight months through June, some analysts expect to see the supply-demand balance tighten soon.
Government data last week showed U.S. natural gas production in June had finally dropping below the same year-ago month for the first time this year. (Reporting by Joe Silha, editing by John Picinich)
U.S. natural gas drilling rigs have been in a mostly steady decline since peaking above 1,600 in September, and now stand at 869 rigs, or 57 percent, below the same week last year.
It is the lowest natural gas rig count since May 3, 2002, when there were 640 rigs operating.
Sources noted the gas rig count decline seemed to be slowing since first falling below the 700 mark five weeks ago.
Tighter access to credit and a 70 percent slide in natural gas prices to about $3.50 per mmBtu after peaking above $13 last July have forced many producers to scale back drilling operations.
But with the natural gas drilling rig count now firmly entrenched below 700, and monthly production down four straight months through June, some analysts expect to see the supply-demand balance tighten soon.
Government data last week showed U.S. natural gas production in June had finally dropping below the same year-ago month for the first time this year. (Reporting by Joe Silha, editing by John Picinich)
Saturday, July 18, 2009
Natural Gas Looking Plentiful
July 17 (Bloomberg) -- Natural gas futures, the worst performing commodity in 2009, may fall to seven-year lows as demand drops with the deepest recession in half a century.
Because chemical plants and power producers are burning less, gas inventories rose to 2.886 trillion cubic feet in the week ended July 10, the highest for any week in July since at least 1994, the U.S. Energy Department reported yesterday. Natural gas is down 36 percent this year on the New York Mercantile Exchange, compared with a 39 percent gain in oil.
The world’s biggest hedge funds hold their largest position against Nymex natural gas futures in seven months, betting at least $5.8 billion on lower prices, Commodity Futures Trading Commission data show. A price drop will hurt producers BP Plc and Exxon Mobil Corp. while lowering costs for power and household air conditioning this summer.
“There’s too much supply and not enough demand,” said Michael Hiley, head of energy OTC at Newedge USA LLC in New York, who expects gas to drop below $3 per million British thermal units by October. “Storage is going to be like a big balloon blown up and you can’t add any more air.”
Gas futures for August delivery to the Henry Hub in Erath, Louisiana, rose 0.1 cent to settle at $3.669 per million Btu at 2:53 p.m. today. Gas was last below $3 in August 2002, one month shy of seven years ago.
Prices on April 27 touched $3.155, the lowest since Sept. 5, 2002, on concern the supply glut will persist throughout the year. Futures rose 8.8 percent this week, after gas climbed 38.5 cents, or 12 percent, to $3.668 per million Btu yesterday.
Net-Short Positions
Hedge fund managers and other large speculators increased their net-short positions in New York futures by 5 percent in the week ended July 7 to 160,481 contracts, approaching the record 177,606 contracts in the week ended Sept. 30, the CFTC data show. Short positions are bets that prices will fall.
Inventories are 19 percent above the five-year average, according to the Energy Department. Industrial gas consumption is forecast to drop 8.2 percent this year and total demand will slide 2.3 percent to 62.1 billion cubic feet a day, the department said July 7 in its monthly Short-Term Energy Outlook.
“I wouldn’t be surprised if we get Nymex Henry Hub prices at $2-something” in the next 30 days, said Rehan Rashid, an analyst at Friedman Billings Ramsey in Arlington, Virginia. “There’s too much supply, weather is pretty nice and then the overall economy.”
Exxon Mobil pumped 10.195 billion cubic feet of gas a day during the first quarter, 49 percent of it in Europe, a public filing showed. U.S. fields accounted for 12 percent of the Irving, Texas-based company’s worldwide gas output during the quarter. Natural gas was 41 percent of its combined crude and gas production during the January-to-March period, the filing showed.
BP Production
London-based BP produced 8.767 billion cubic feet of gas a day during the first three months of the year, or 36 percent of its total hydrocarbon output, a public filing showed. U.S. wells accounted for 27 percent of the company’s global gas production. BP is the largest producer of gas from American wells, according to the Washington-based Natural Gas Supply Association.
Companies put natural gas into underground storage from April through October to have enough on hand to meet peak demand during the winter. Stockpiles have been above average levels since last August as factory shutdowns caused demand to plummet.
Winter heating demand may help reverse the price decline. Joe Bastardi, chief meteorologist at AccuWeather.com, expects the snowiest winter in more than five years along the eastern seaboard and northern plains, according to a July 15 report. Gas demand in the U.S. typically peaks in January and February.
Worst Performer
Natural gas has been the worst performer in the S&P GSCI Commodity Index this year. As it fell, copper jumped 72 percent, gold appreciated 6 percent and gasoline advanced 70 percent.
The risk is a reversal in the trend by the end of 2009 as the recession eases and industrial demand returns, according to estimates by analysts and investors compiled by Bloomberg.
Falling prices have forced drillers to cut back on exploration. U.S. gas production will fall 0.6 percent this year, according to the U.S. Energy Department estimates. Gas rigs operating in the U.S. last week fell to 672, the lowest since May 2002, according to data published by Baker Hughes Inc.
“If we continue this slowdown or cessation of drilling activity, there will be, at some point, not enough gas to go around,” said Dewey Bartlett Jr., chairman of the National Stripper Well Association, a nonprofit trade group of small energy producers. Bartlett is president and owner of Keener Oil Co. in Tulsa, Oklahoma.
Average Price
Natural gas will probably average $4.97 per million Btu this quarter, based on an average of eight analyst estimates collected by Bloomberg since May. Prices will then increase to an average $5.78 in the fourth quarter, according to the estimates.
“It’s more about declining wellhead production than anything else,” said Roger Read, an analyst at Natixis Bleichroeder Inc. in Houston, who expects gas to average $3.50 per million Btu in the third quarter and $5.50 in the fourth.
Figures from the Federal Reserve this week showed the smallest contraction in industrial production in more than a year, a sign the worst may be past for manufacturers. The New York Fed’s Empire Index rose to minus 0.6 in July from minus 9.4 a month earlier.
Industrial Production
“There are signals that industrial production in the U.S. is bottoming out in terms of year-on-year contraction, and that’s a positive sign,” said James Crandell, a commodities research analyst at Barclays Capital in New York. Crandell said gas will average $3.80 in the third quarter and $4 in the final three months. The Nymex futures markets are trading at $3.72 in the third quarter and $4.65 in the fourth, according to data compiled by Bloomberg.
The American Iron and Steel Institute’s steel production index has risen 18 percent since the end of December, when output dropped to the lowest since at least 1980. U.S. mills last week were operating above 50 percent of capacity for the first time since Dec. 1.
“The increased use from steel manufacturing in the U.S. since the beginning of July could be a green shoot that would actually turn into really good news,” said Laurent Key, a New York-based economist for Societe Generale SA who expects gas to drop to between $2.90 and $3 by October and average $3.33 in the fourth quarter. “It’s too early to talk about a recovery.”
Key said the U.S. may have the highest inventory levels of the year in October, causing prices to bottom out below $3.
Low Prices
Prices are “really, really low” because the industry has been successful in exploring for natural gas, said Bartlett of the stripper well association.
“It’s going to be a while” before the glut ends, Bartlett said. “There’s such a huge volume of gas in storage, and it’s not getting out at a decent rate.”
U.S. potential natural gas resources rose 39 percent from two years ago to 1,836 trillion cubic feet, the highest level on record, according to an industry report issued last month.
Most of the increase in potential natural gas reserves came from a reassessment of shale gas in the Appalachian basin and in the mid-continent, Gulf Coast and Rocky Mountain areas, according to a report by the Potential Gas Committee, a group of industry, government and academic volunteers.
Decades of Gas
Shale gas is locked in non-porous rock that made the reserves inaccessible until producers perfected new drilling techniques in the 1990s.
When the potential is combined with the Energy Department’s latest determination of proved gas reserves, at 238 trillion cubic feet as of year-end 2007, the U.S. has a total available future supply of 2,074 trillion cubic feet. The U.S. consumes about 23 trillion cubic feet of natural gas a year, including 6.6 trillion for electricity.
“Gas prices got to a point where it was economical to produce from shale, and everyone started up,” said Hiley of Newedge USA. “Now it’s on the market, and it’s hurting.
“I would not be surprised to see a $2 handle,” Hiley said.
To contact the reporter on this story: Margot Habiby in Dallas at mhabiby@bloomberg.net.
Because chemical plants and power producers are burning less, gas inventories rose to 2.886 trillion cubic feet in the week ended July 10, the highest for any week in July since at least 1994, the U.S. Energy Department reported yesterday. Natural gas is down 36 percent this year on the New York Mercantile Exchange, compared with a 39 percent gain in oil.
The world’s biggest hedge funds hold their largest position against Nymex natural gas futures in seven months, betting at least $5.8 billion on lower prices, Commodity Futures Trading Commission data show. A price drop will hurt producers BP Plc and Exxon Mobil Corp. while lowering costs for power and household air conditioning this summer.
“There’s too much supply and not enough demand,” said Michael Hiley, head of energy OTC at Newedge USA LLC in New York, who expects gas to drop below $3 per million British thermal units by October. “Storage is going to be like a big balloon blown up and you can’t add any more air.”
Gas futures for August delivery to the Henry Hub in Erath, Louisiana, rose 0.1 cent to settle at $3.669 per million Btu at 2:53 p.m. today. Gas was last below $3 in August 2002, one month shy of seven years ago.
Prices on April 27 touched $3.155, the lowest since Sept. 5, 2002, on concern the supply glut will persist throughout the year. Futures rose 8.8 percent this week, after gas climbed 38.5 cents, or 12 percent, to $3.668 per million Btu yesterday.
Net-Short Positions
Hedge fund managers and other large speculators increased their net-short positions in New York futures by 5 percent in the week ended July 7 to 160,481 contracts, approaching the record 177,606 contracts in the week ended Sept. 30, the CFTC data show. Short positions are bets that prices will fall.
Inventories are 19 percent above the five-year average, according to the Energy Department. Industrial gas consumption is forecast to drop 8.2 percent this year and total demand will slide 2.3 percent to 62.1 billion cubic feet a day, the department said July 7 in its monthly Short-Term Energy Outlook.
“I wouldn’t be surprised if we get Nymex Henry Hub prices at $2-something” in the next 30 days, said Rehan Rashid, an analyst at Friedman Billings Ramsey in Arlington, Virginia. “There’s too much supply, weather is pretty nice and then the overall economy.”
Exxon Mobil pumped 10.195 billion cubic feet of gas a day during the first quarter, 49 percent of it in Europe, a public filing showed. U.S. fields accounted for 12 percent of the Irving, Texas-based company’s worldwide gas output during the quarter. Natural gas was 41 percent of its combined crude and gas production during the January-to-March period, the filing showed.
BP Production
London-based BP produced 8.767 billion cubic feet of gas a day during the first three months of the year, or 36 percent of its total hydrocarbon output, a public filing showed. U.S. wells accounted for 27 percent of the company’s global gas production. BP is the largest producer of gas from American wells, according to the Washington-based Natural Gas Supply Association.
Companies put natural gas into underground storage from April through October to have enough on hand to meet peak demand during the winter. Stockpiles have been above average levels since last August as factory shutdowns caused demand to plummet.
Winter heating demand may help reverse the price decline. Joe Bastardi, chief meteorologist at AccuWeather.com, expects the snowiest winter in more than five years along the eastern seaboard and northern plains, according to a July 15 report. Gas demand in the U.S. typically peaks in January and February.
Worst Performer
Natural gas has been the worst performer in the S&P GSCI Commodity Index this year. As it fell, copper jumped 72 percent, gold appreciated 6 percent and gasoline advanced 70 percent.
The risk is a reversal in the trend by the end of 2009 as the recession eases and industrial demand returns, according to estimates by analysts and investors compiled by Bloomberg.
Falling prices have forced drillers to cut back on exploration. U.S. gas production will fall 0.6 percent this year, according to the U.S. Energy Department estimates. Gas rigs operating in the U.S. last week fell to 672, the lowest since May 2002, according to data published by Baker Hughes Inc.
“If we continue this slowdown or cessation of drilling activity, there will be, at some point, not enough gas to go around,” said Dewey Bartlett Jr., chairman of the National Stripper Well Association, a nonprofit trade group of small energy producers. Bartlett is president and owner of Keener Oil Co. in Tulsa, Oklahoma.
Average Price
Natural gas will probably average $4.97 per million Btu this quarter, based on an average of eight analyst estimates collected by Bloomberg since May. Prices will then increase to an average $5.78 in the fourth quarter, according to the estimates.
“It’s more about declining wellhead production than anything else,” said Roger Read, an analyst at Natixis Bleichroeder Inc. in Houston, who expects gas to average $3.50 per million Btu in the third quarter and $5.50 in the fourth.
Figures from the Federal Reserve this week showed the smallest contraction in industrial production in more than a year, a sign the worst may be past for manufacturers. The New York Fed’s Empire Index rose to minus 0.6 in July from minus 9.4 a month earlier.
Industrial Production
“There are signals that industrial production in the U.S. is bottoming out in terms of year-on-year contraction, and that’s a positive sign,” said James Crandell, a commodities research analyst at Barclays Capital in New York. Crandell said gas will average $3.80 in the third quarter and $4 in the final three months. The Nymex futures markets are trading at $3.72 in the third quarter and $4.65 in the fourth, according to data compiled by Bloomberg.
The American Iron and Steel Institute’s steel production index has risen 18 percent since the end of December, when output dropped to the lowest since at least 1980. U.S. mills last week were operating above 50 percent of capacity for the first time since Dec. 1.
“The increased use from steel manufacturing in the U.S. since the beginning of July could be a green shoot that would actually turn into really good news,” said Laurent Key, a New York-based economist for Societe Generale SA who expects gas to drop to between $2.90 and $3 by October and average $3.33 in the fourth quarter. “It’s too early to talk about a recovery.”
Key said the U.S. may have the highest inventory levels of the year in October, causing prices to bottom out below $3.
Low Prices
Prices are “really, really low” because the industry has been successful in exploring for natural gas, said Bartlett of the stripper well association.
“It’s going to be a while” before the glut ends, Bartlett said. “There’s such a huge volume of gas in storage, and it’s not getting out at a decent rate.”
U.S. potential natural gas resources rose 39 percent from two years ago to 1,836 trillion cubic feet, the highest level on record, according to an industry report issued last month.
Most of the increase in potential natural gas reserves came from a reassessment of shale gas in the Appalachian basin and in the mid-continent, Gulf Coast and Rocky Mountain areas, according to a report by the Potential Gas Committee, a group of industry, government and academic volunteers.
Decades of Gas
Shale gas is locked in non-porous rock that made the reserves inaccessible until producers perfected new drilling techniques in the 1990s.
When the potential is combined with the Energy Department’s latest determination of proved gas reserves, at 238 trillion cubic feet as of year-end 2007, the U.S. has a total available future supply of 2,074 trillion cubic feet. The U.S. consumes about 23 trillion cubic feet of natural gas a year, including 6.6 trillion for electricity.
“Gas prices got to a point where it was economical to produce from shale, and everyone started up,” said Hiley of Newedge USA. “Now it’s on the market, and it’s hurting.
“I would not be surprised to see a $2 handle,” Hiley said.
To contact the reporter on this story: Margot Habiby in Dallas at mhabiby@bloomberg.net.
EU Wary of Russian Natural Gas
A directive announced today by the European Union will do little to relieve the bloc's dependence on Russian natural gas -- nor should it, analysts say.
It is "pure fantasy" to think Europe could wean itself from Russian natural gas, which fulfills 25 percent of the European Union's demand, said Julian Lee, a senior energy analyst at the Centre for Global Energy Studies in London.
Rather, Europe should try to diversify the ways it gets Russian gas, adding pipelines that avoid troubled former Soviet states. Historically, Russia and Gazprom, its state-owned gas agency, have been reliable partners to the European Union, rather than a looming energy menace, analysts said.
The E.U. directive, proposed by its executive arm, the European Commission, calls for each member state to prepare itself for a disruption of its largest gas supply for at least two months during the depths of winter, when demand is at its highest.
"We have known for some time that the existing arrangements to deal with gas emergencies are insufficient," E.U. Energy Commissioner Andris Piebalgs said. "The Russia-Ukraine gas dispute in January 2009 confirmed our fears."
Many feel that the commission, which accelerated its issuing of the directive in response to the latest gas crisis, has been tardy in its proposal.
"I think this is something, frankly, that the E.U. should have done several years ago," Lee said. "And it's finally got its act together."
Nearly all Russian gas runs through Belarus and Ukraine, former Soviet states that Russia regards as within its sphere of influence. On several occasions, Russia has shut off the supply of gas to Ukraine, most recently this past January when the countries were debating gas prices.
Several eastern E.U. countries, like Slovakia and Bulgaria, that depend on Ukraine's pipelines for all their gas became innocent bystanders in the January dispute. Reports emerged of kindergartens closing for lack of heat and similar crises.
These countries can prepare for disruptions in several ways, principally by diversifying their gas pipelines or increasing their total gas storage, said Ferran Tarradellas Espuny, Piebalgs' spokesman.
"Each member state must be prepared to face such a crisis," he said.
Some supply solutions are simple to implement. Slovakia, for example, relies on Ukrainian pipelines for 97 percent of its gas, but with some minor engineering work, the east-west flow of the pipe can be reversed, allowing imports from well-supplied Germany.
While there has been broad support for improved coordination on gas, some of the Western European countries may balk at helping their peers to the east.
"The E.U.-wide sharing of existing [gas] storage may be resisted by those with plenty of storage," said Jonathan Stern, director of gas research at the Oxford Institute of Energy Studies. There could be accusations, he added, of "free riding."
Major investments needed
The European Union estimated that €150 billion ($211 billion) needs to be spent on gas infrastructure by 2030. The European Union will help fund some of this work, but much investment needs to come from individual countries and industry, according to Piebalgs.
Increasing the use of liquefied natural gas (LNG), which can be shipped in tankers, is also part of the solution; Britain recently opened its third LNG terminal. However, many of the eastern E.U. countries hardest hit by the January crisis are landlocked, and increasing LNG flow to them could call for further reliance on Turkey, Lee said. It is a "major question" how much LNG the European Union can import, Stern added.
Other steps will be more difficult. Many southeastern E.U. countries are anticipating the construction of two new gas pipelines. The first, called Nabucco, will grant gas providers like Iraq and Azerbaijan access to E.U. markets for the first time. A formal agreement among five E.U. nations and Turkey was announced Monday granting legal clearance for Nabucco, which could begin flowing by 2014.
Russia, which could supply gas to Nabucco, has also proposed a southern pipeline, called South Stream, that avoids flowing through Ukraine and Belarus. Italy has strongly supported the pipeline, and Germany has shown similar interest in another pipeline, called Nord Stream, which would flow from Russia to Germany under the Baltic Sea.
Nord Stream, in particular, will provide economic advantages to German industry, which depends dearly on Russian gas, said Jon Levy, an analyst for the Eurasia Group.
Purely from the standpoint of energy security, Europe would be smart to shift its gas infrastructure out of former Soviet states to avoid future troubles between Russia and its former dominions, Stern said.
Such a position gets strong political opposition from many E.U. leaders, who "are very careful in their approach to anything that would destabilize Ukraine," Levy said. Many European banks are deeply invested in the country and want to see it politically stable.
'The big kid in the playground'
While equal portions of blame can be doled to Ukraine and Russia for the most recent crisis, E.U. leaders have fixed on Russia because, compared to Ukraine, "It's the big kid in the playground flexing its muscles," Lee said. Plus, Russia did appear "very willing to turn [its dispute with Ukraine] into a European problem."
E.U. officials are set to hold talks tomorrow with Gazprom and its Ukrainian counterpart. The latter is asking for a multibillion-dollar loan to help pay its debts to Gazprom. Any loan will be linked to a promise no further disruptions will occur, the European Union said.
Demand for Russian gas will decline dramatically this year, largely thanks to the recession, and probably won't recover for another one to two years, Stern said. While an influx of Central Asian gas through Nabucco, which the United States has strongly supported, could be a blow to Russia's market share, the mutual economic dependence between the regions will continue for some time.
What should not be forgotten is that since the 1970s, Russia has reliably provided gas to Europe through all sorts of upheaval, Lee said.
"There's a lot of expertise and trust there," he said, "that have survived some very fundamental political differences."
Copyright 2009 E&E Publishing. All Rights Reserved.
For more news on energy and the environment, visit www.greenwire.com.
http://www.nytimes.com/gwire/2009/07/16/16greenwire-wary-eu-girding-for-disruptions-of-russian-nat-68228.html
It is "pure fantasy" to think Europe could wean itself from Russian natural gas, which fulfills 25 percent of the European Union's demand, said Julian Lee, a senior energy analyst at the Centre for Global Energy Studies in London.
Rather, Europe should try to diversify the ways it gets Russian gas, adding pipelines that avoid troubled former Soviet states. Historically, Russia and Gazprom, its state-owned gas agency, have been reliable partners to the European Union, rather than a looming energy menace, analysts said.
The E.U. directive, proposed by its executive arm, the European Commission, calls for each member state to prepare itself for a disruption of its largest gas supply for at least two months during the depths of winter, when demand is at its highest.
"We have known for some time that the existing arrangements to deal with gas emergencies are insufficient," E.U. Energy Commissioner Andris Piebalgs said. "The Russia-Ukraine gas dispute in January 2009 confirmed our fears."
Many feel that the commission, which accelerated its issuing of the directive in response to the latest gas crisis, has been tardy in its proposal.
"I think this is something, frankly, that the E.U. should have done several years ago," Lee said. "And it's finally got its act together."
Nearly all Russian gas runs through Belarus and Ukraine, former Soviet states that Russia regards as within its sphere of influence. On several occasions, Russia has shut off the supply of gas to Ukraine, most recently this past January when the countries were debating gas prices.
Several eastern E.U. countries, like Slovakia and Bulgaria, that depend on Ukraine's pipelines for all their gas became innocent bystanders in the January dispute. Reports emerged of kindergartens closing for lack of heat and similar crises.
These countries can prepare for disruptions in several ways, principally by diversifying their gas pipelines or increasing their total gas storage, said Ferran Tarradellas Espuny, Piebalgs' spokesman.
"Each member state must be prepared to face such a crisis," he said.
Some supply solutions are simple to implement. Slovakia, for example, relies on Ukrainian pipelines for 97 percent of its gas, but with some minor engineering work, the east-west flow of the pipe can be reversed, allowing imports from well-supplied Germany.
While there has been broad support for improved coordination on gas, some of the Western European countries may balk at helping their peers to the east.
"The E.U.-wide sharing of existing [gas] storage may be resisted by those with plenty of storage," said Jonathan Stern, director of gas research at the Oxford Institute of Energy Studies. There could be accusations, he added, of "free riding."
Major investments needed
The European Union estimated that €150 billion ($211 billion) needs to be spent on gas infrastructure by 2030. The European Union will help fund some of this work, but much investment needs to come from individual countries and industry, according to Piebalgs.
Increasing the use of liquefied natural gas (LNG), which can be shipped in tankers, is also part of the solution; Britain recently opened its third LNG terminal. However, many of the eastern E.U. countries hardest hit by the January crisis are landlocked, and increasing LNG flow to them could call for further reliance on Turkey, Lee said. It is a "major question" how much LNG the European Union can import, Stern added.
Other steps will be more difficult. Many southeastern E.U. countries are anticipating the construction of two new gas pipelines. The first, called Nabucco, will grant gas providers like Iraq and Azerbaijan access to E.U. markets for the first time. A formal agreement among five E.U. nations and Turkey was announced Monday granting legal clearance for Nabucco, which could begin flowing by 2014.
Russia, which could supply gas to Nabucco, has also proposed a southern pipeline, called South Stream, that avoids flowing through Ukraine and Belarus. Italy has strongly supported the pipeline, and Germany has shown similar interest in another pipeline, called Nord Stream, which would flow from Russia to Germany under the Baltic Sea.
Nord Stream, in particular, will provide economic advantages to German industry, which depends dearly on Russian gas, said Jon Levy, an analyst for the Eurasia Group.
Purely from the standpoint of energy security, Europe would be smart to shift its gas infrastructure out of former Soviet states to avoid future troubles between Russia and its former dominions, Stern said.
Such a position gets strong political opposition from many E.U. leaders, who "are very careful in their approach to anything that would destabilize Ukraine," Levy said. Many European banks are deeply invested in the country and want to see it politically stable.
'The big kid in the playground'
While equal portions of blame can be doled to Ukraine and Russia for the most recent crisis, E.U. leaders have fixed on Russia because, compared to Ukraine, "It's the big kid in the playground flexing its muscles," Lee said. Plus, Russia did appear "very willing to turn [its dispute with Ukraine] into a European problem."
E.U. officials are set to hold talks tomorrow with Gazprom and its Ukrainian counterpart. The latter is asking for a multibillion-dollar loan to help pay its debts to Gazprom. Any loan will be linked to a promise no further disruptions will occur, the European Union said.
Demand for Russian gas will decline dramatically this year, largely thanks to the recession, and probably won't recover for another one to two years, Stern said. While an influx of Central Asian gas through Nabucco, which the United States has strongly supported, could be a blow to Russia's market share, the mutual economic dependence between the regions will continue for some time.
What should not be forgotten is that since the 1970s, Russia has reliably provided gas to Europe through all sorts of upheaval, Lee said.
"There's a lot of expertise and trust there," he said, "that have survived some very fundamental political differences."
Copyright 2009 E&E Publishing. All Rights Reserved.
For more news on energy and the environment, visit www.greenwire.com.
http://www.nytimes.com/gwire/2009/07/16/16greenwire-wary-eu-girding-for-disruptions-of-russian-nat-68228.html
Friday, July 17, 2009
Natural Gas Up & Down Again
By ERNEST SCHEYDER (AP) – 16 hours ago
NEW YORK — Natural gas stockpile levels jumped last week, though the increase met expectations and demand for the fuel continues to sag, the government said Thursday.
The Energy Department's Energy Information Administration said in its weekly report that natural gas inventories held in underground storage in the lower 48 states rose by 90 billion cubic feet to about 2.89 trillion cubic feet for the week ended July 10.
Analysts had expected a boost of between 89 billion and 93 billion cubic feet, according to a survey by Platts, the energy information arm of McGraw-Hill Cos.
The inventory level was 19 percent above the five-year average of about 2.43 trillion cubic feet, and 26 percent above last year's storage level of about 2.30 trillion cubic feet, according to the government data.
Natural gas rose 18 cents to $3.463 per 1,000 cubic feet on the New York Mercantile Exchange.
Copyright © 2009 The Associated Press. All rights reserved.
NEW YORK — Natural gas stockpile levels jumped last week, though the increase met expectations and demand for the fuel continues to sag, the government said Thursday.
The Energy Department's Energy Information Administration said in its weekly report that natural gas inventories held in underground storage in the lower 48 states rose by 90 billion cubic feet to about 2.89 trillion cubic feet for the week ended July 10.
Analysts had expected a boost of between 89 billion and 93 billion cubic feet, according to a survey by Platts, the energy information arm of McGraw-Hill Cos.
The inventory level was 19 percent above the five-year average of about 2.43 trillion cubic feet, and 26 percent above last year's storage level of about 2.30 trillion cubic feet, according to the government data.
Natural gas rose 18 cents to $3.463 per 1,000 cubic feet on the New York Mercantile Exchange.
Copyright © 2009 The Associated Press. All rights reserved.
Thursday, July 16, 2009
Natural Gas and TBoone Still Going Strong
NEW YORK — The past year has been tough on T. Boone Pickens and his $60 million mission to wean America off of foreign oil.
Over the past 12 months, Pickens pressed the public to rethink its use of energy. His "Pickens Plan" called for a number of changes such as investing in wind and solar energy, rebuilding the country's electrical grid and replacing gasoline with natural gas in cars and trucks.
Pickens says he was influential in starting a national dialog on energy and helped draft legislation that would give tax incentives for natural gas-burning vehicles.
But after spending millions on television commercials and a public relations tour that took him to 74 cities and 22 town halls, his plan has run into some sizeable hurdles, most notably a crash in energy prices. As prices plunged, the Texas billionaire's hedge funds lost billions of dollars. Pickens also scrapped plans for the world's biggest wind farm, and California voters rejected a natural gas initiative he backed.
"I do wonder how long that I can continue at the pace," Pickens, 81, said Tuesday in an interview with Associated Press reporters and editors. "I know my time is limited. I'm in a hurry. I want to get this done."During the past year, Congress has approved incentive programs that will funnel billions of dollars to solar, wind and other renewable energy programs. The House of Representatives passed an energy bill that would create a cap-and-trade system for carbon dioxide emissions.
"I think we should be given credit for some part of that," he said.
When Pickens announced his plan last year at this time, oil cost more than $130 a barrel and gasoline went for more than $4 per gallon. Crude has since fallen as low as $32.70 and now trades at $62.34.
Gasoline costs about $2.61 at the peak of the driving season.
While slumping energy prices have been a silver lining during the recession, there are some fears that the urgency to build solar, and for Pickens, wind power, is now diminished. For example, the natural gas that power companies use now costs less than half of what it did last year, making it harder for wind to compete.
The Texas oil man made a big splash last year by leasing about 200,000 acres in West Texas for a massive 1000 megawatt wind farm. But he said Tuesday that the plan has fallen apart because of technical problems concerning transmission.
"We're not going to be able to do them (in Texas), at this point," he said.
Pickens said he already has 687 wind turbines on order from General Electric, and he'll probably spread them among other projects.
The Pickens Plan also calls for building fleets of cars and trucks to burn natural gas.
But so far efforts have failed to create incentives for natural gas vehicles.
Last year, Pickens' Clean Energy Fuels Corp. pumped $19 million into a California bond initiative that would have handed rebates to people who bought natural gas and other alternative-fuel vehicles. But critics said the measure would have steered taxpayer dollars to Pickens, who is the majority shareholder of a company that supplies natural gas for transportation, and voters rejected it.
He's now pushing for a similar measure in Congress.
On Wednesday, Pickens will release a new ad promoting natural gas as an alternative fuel for cars and trucks. He said he will also be in Washington standing next to Sens. Robert Menendez, and Harry Reid when a natural gas bill is announced.
He's also embarking on another tour around the country to remind the public that even though oil prices are lower than last year, the world still faces an energy crisis.
People are driving more cars every year, and OPEC revenues keep increasing.
Without an energy plan that cuts the country's dependency on oil, "I'll tell you where you're going to be. You're going to be importing 75 percent of your oil, and you'll be paying $300 a barrel for it," he said.
Pickens said that federal support for natural gas vehicles would give his energy plan a true victory. So would energy legislation that installs a cap-and-trade system. That bill passed the House this summer and is waiting to be taken up by the Senate, he said.
"That would be the most far reaching legislation on energy in the history of America," he said. "If that happens, then I'll know I'll be successful."
Pickens said he might be able to go back to his day job if those bills pass. Until then, he'll keep pushing the issue any way he can.
"This is going to work," Pickens said, pointing his finger at reporters as the elevator doors closed and his entourage headed down to the street.
Over the past 12 months, Pickens pressed the public to rethink its use of energy. His "Pickens Plan" called for a number of changes such as investing in wind and solar energy, rebuilding the country's electrical grid and replacing gasoline with natural gas in cars and trucks.
Pickens says he was influential in starting a national dialog on energy and helped draft legislation that would give tax incentives for natural gas-burning vehicles.
But after spending millions on television commercials and a public relations tour that took him to 74 cities and 22 town halls, his plan has run into some sizeable hurdles, most notably a crash in energy prices. As prices plunged, the Texas billionaire's hedge funds lost billions of dollars. Pickens also scrapped plans for the world's biggest wind farm, and California voters rejected a natural gas initiative he backed.
"I do wonder how long that I can continue at the pace," Pickens, 81, said Tuesday in an interview with Associated Press reporters and editors. "I know my time is limited. I'm in a hurry. I want to get this done."During the past year, Congress has approved incentive programs that will funnel billions of dollars to solar, wind and other renewable energy programs. The House of Representatives passed an energy bill that would create a cap-and-trade system for carbon dioxide emissions.
"I think we should be given credit for some part of that," he said.
When Pickens announced his plan last year at this time, oil cost more than $130 a barrel and gasoline went for more than $4 per gallon. Crude has since fallen as low as $32.70 and now trades at $62.34.
Gasoline costs about $2.61 at the peak of the driving season.
While slumping energy prices have been a silver lining during the recession, there are some fears that the urgency to build solar, and for Pickens, wind power, is now diminished. For example, the natural gas that power companies use now costs less than half of what it did last year, making it harder for wind to compete.
The Texas oil man made a big splash last year by leasing about 200,000 acres in West Texas for a massive 1000 megawatt wind farm. But he said Tuesday that the plan has fallen apart because of technical problems concerning transmission.
"We're not going to be able to do them (in Texas), at this point," he said.
Pickens said he already has 687 wind turbines on order from General Electric, and he'll probably spread them among other projects.
The Pickens Plan also calls for building fleets of cars and trucks to burn natural gas.
But so far efforts have failed to create incentives for natural gas vehicles.
Last year, Pickens' Clean Energy Fuels Corp. pumped $19 million into a California bond initiative that would have handed rebates to people who bought natural gas and other alternative-fuel vehicles. But critics said the measure would have steered taxpayer dollars to Pickens, who is the majority shareholder of a company that supplies natural gas for transportation, and voters rejected it.
He's now pushing for a similar measure in Congress.
On Wednesday, Pickens will release a new ad promoting natural gas as an alternative fuel for cars and trucks. He said he will also be in Washington standing next to Sens. Robert Menendez, and Harry Reid when a natural gas bill is announced.
He's also embarking on another tour around the country to remind the public that even though oil prices are lower than last year, the world still faces an energy crisis.
People are driving more cars every year, and OPEC revenues keep increasing.
Without an energy plan that cuts the country's dependency on oil, "I'll tell you where you're going to be. You're going to be importing 75 percent of your oil, and you'll be paying $300 a barrel for it," he said.
Pickens said that federal support for natural gas vehicles would give his energy plan a true victory. So would energy legislation that installs a cap-and-trade system. That bill passed the House this summer and is waiting to be taken up by the Senate, he said.
"That would be the most far reaching legislation on energy in the history of America," he said. "If that happens, then I'll know I'll be successful."
Pickens said he might be able to go back to his day job if those bills pass. Until then, he'll keep pushing the issue any way he can.
"This is going to work," Pickens said, pointing his finger at reporters as the elevator doors closed and his entourage headed down to the street.
Wednesday, July 15, 2009
EU Natural Gas Consortium Flexing Tiny Muscles
CFA Institute Financial NewsBrief | 07/14/2009
After years of painstaking negotiations, the EU and Turkey cleared the way for construction of a natural gas pipeline that could end Europe's dependence on gas from Russia. The agreement to build the Nabucco pipeline from the Caspian Sea to Austria was signed by the prime ministers of the nations through which the pipeline will run: Austria, Bulgaria, Hungary, Romania and Turkey. The route bypasses Russia. Spiegel Online (Germany) (13 Jul.)
The proposed Nabucco pipeline would run from Turkey's eastern border, through Bulgaria, Romania and Hungary, to a key gas terminal in Baumgarten, Austria.
Germany is also a partner in the deal, which is being signed in the Turkish capital, Ankara.
Russia controls the current network of pipelines that supply Europe with natural gas.
To challenge the Nabucco proposal, Russia has proposed a competing natural gas pipeline to southeastern Europe. The South Stream pipeline would pass under the Black Sea and connect with Bulgaria. Russia and Italy would each control half of that pipeline. See map of pipeline »
However, Nabucco got a boost after Russia turned off the gas to Europe in January, during the latest in a series of price disputes with Ukraine, according to industry analysts.
The Nabucco project is budgeted at €7.9 billion (about $11 billion).
Since the idea's inception in 2002, plans for Nabucco have languished amid disagreements among consortium partners and lack of commitment from natural gas suppliers.
Turkey had demanded to retain 15 percent of the gas passing through the pipeline for consumption and export, which its European partners rejected.
The energy minister of Azerbaijan is expected to attend Monday's signing, a top Western government official said. Gas from Azerbaijan's Shah Deniz 2 field will be a crucial component of the project. European officials have raised hopes that other gas producers, such as Iraq and Turkmenistan, also might contribute to the pipeline.
Big hurdles remain for the pipeline project named after an opera by Verdi.
Consortium members must raise billions of dollars for the Nabucco project. Construction has not begun, and gas is not projected to be pumped through until 2014.
Still, industry analysts called Monday's intergovernmental agreement a significant development. "It's one of those steps that moves Nabucco out of the possible column and into the probable column," said John Roberts, an energy security specialist with Platts.
"My own guess is roughly by the end of the year, it will be pretty clear that Nabucco will be built."
E-mail to a friend E-mail to a friend
Share this on:
Mixx Facebook Twitter Digg del.icio.us reddit MySpace StumbleUpon
| Mixx it | Share
After years of painstaking negotiations, the EU and Turkey cleared the way for construction of a natural gas pipeline that could end Europe's dependence on gas from Russia. The agreement to build the Nabucco pipeline from the Caspian Sea to Austria was signed by the prime ministers of the nations through which the pipeline will run: Austria, Bulgaria, Hungary, Romania and Turkey. The route bypasses Russia. Spiegel Online (Germany) (13 Jul.)
The proposed Nabucco pipeline would run from Turkey's eastern border, through Bulgaria, Romania and Hungary, to a key gas terminal in Baumgarten, Austria.
Germany is also a partner in the deal, which is being signed in the Turkish capital, Ankara.
Russia controls the current network of pipelines that supply Europe with natural gas.
To challenge the Nabucco proposal, Russia has proposed a competing natural gas pipeline to southeastern Europe. The South Stream pipeline would pass under the Black Sea and connect with Bulgaria. Russia and Italy would each control half of that pipeline. See map of pipeline »
However, Nabucco got a boost after Russia turned off the gas to Europe in January, during the latest in a series of price disputes with Ukraine, according to industry analysts.
The Nabucco project is budgeted at €7.9 billion (about $11 billion).
Since the idea's inception in 2002, plans for Nabucco have languished amid disagreements among consortium partners and lack of commitment from natural gas suppliers.
Turkey had demanded to retain 15 percent of the gas passing through the pipeline for consumption and export, which its European partners rejected.
The energy minister of Azerbaijan is expected to attend Monday's signing, a top Western government official said. Gas from Azerbaijan's Shah Deniz 2 field will be a crucial component of the project. European officials have raised hopes that other gas producers, such as Iraq and Turkmenistan, also might contribute to the pipeline.
Big hurdles remain for the pipeline project named after an opera by Verdi.
Consortium members must raise billions of dollars for the Nabucco project. Construction has not begun, and gas is not projected to be pumped through until 2014.
Still, industry analysts called Monday's intergovernmental agreement a significant development. "It's one of those steps that moves Nabucco out of the possible column and into the probable column," said John Roberts, an energy security specialist with Platts.
"My own guess is roughly by the end of the year, it will be pretty clear that Nabucco will be built."
E-mail to a friend E-mail to a friend
Share this on:
Mixx Facebook Twitter Digg del.icio.us reddit MySpace StumbleUpon
| Mixx it | Share
Tuesday, July 14, 2009
Natural Gas Behind the Others in Lobbying Congress
The battle over climate legislation will now pit the country's top power sources against each other.Saying they failed to protect their interests as a landmark bill came together and passed the House last month, natural gas executives are forming a strategy to influence rewrites in the Senate.
"There are a lot of people in the industry who are scrambling their forces right now," said Fred Julander, founder and chairman of the Rocky Mountain Natural Gas Strategy Conference, an annual event that drew 1,800 industry people to Denver last week. "Whether we can learn and get up to speed -- and it's a steep learning curve -- is the question."
Battles in the Senate over climate bill language will be intense, and natural gas lags behind its competitors in the race to sway lawmakers.
"Much of what is going on is an industry feeling left out of the party and hoping to get more goodies for itself in the Senate bill," Steven Hayward, fellow at the American Enterprise Institute, a conservative think tank, said of natural gas.
Coal lobbyists have been talking to senators and aides for months, with their contacts becoming more frequent since the House bill passed. Coal lobbyists want to slow down the pace of the House measure's plan to cap greenhouse gas emissions and make businesses buy allowances for those emissions.
Natural gas also will have to compete against the utility industry, which has been lobbying heavily on energy legislation. While they represent natural gas and coal, utilities have big reasons to favor coal.
Electric utilities used coal for 59 percent of their power generation in 2007, while natural gas was used 13 percent of the time, according to the Energy Information Administration. Coal has been less expensive, making it more profitable for utilities to use as a fuel source.
Lobbying by utility interests so far has dwarfed competitors. In the first quarter of this year, utilities spent $35.1 million on lobbying. The natural gas industry spent less than a tenth of that, $3.3 million. Of the top 10 industries with a stake in climate legislation, natural gas put the least money into lobbying in the first quarter, according to a recent E&E analysis.
"As a whole, we're not very sophisticated in terms of public relations, and we need to be," Julander said. "We need to grow up and get in this game. No one is going to give us anything, even though we're the best for the environment."
'Coal Preservation Act'
Coal and natural gas are the top fuels used to make electricity in the United States. Natural gas emits about half the carbon dioxide, the principal greenhouse gas, that coal does for the same amount of energy produced. Natural gas executives and others at the Denver conference argued that while the House-passed legislation strives to reduce carbon emissions, it insulates coal in a way that will hurt lower-emitting natural gas.
Analysts agree that the bill crafted by Reps. Henry Waxman (D-Calif.) and Ed Markey (D-Mass.) helps coal.
"Coal did very well in Waxman-Markey," said AEI's Hayward, who added that the legislation could be called the "Sleight-Of-Hand Coal Preservation Act."
"It is so well-established in so many industrial states, and replacing it with another source, even natural gas, would cause a serious increase in utility rates, which no politician wants their fingerprints on," said Hayward, who in general dislikes the bill.
A spokesman for a trade group representing coal interests said the bill is structured to lower carbon emissions while still protecting consumers from higher electricity costs.
"The reality is, natural gas is a higher-priced fuel. It's a less domestically available fuel," said Joe Lucas, spokesman for American Coalition for Clean Coal Electricity. Language in the bill helping utilities that use coal "is a way of reducing the consumer's end price."
In the early years of climate regulation that charges for carbon emissions, the government would give away 85 percent of the carbon emission allowances and auction the remaining 15 percent.
http://www.nytimes.com/gwire/2009/07/13/13greenwire-at-center-ring-in-senate-climate-debate-coal-v-32201.html
"There are a lot of people in the industry who are scrambling their forces right now," said Fred Julander, founder and chairman of the Rocky Mountain Natural Gas Strategy Conference, an annual event that drew 1,800 industry people to Denver last week. "Whether we can learn and get up to speed -- and it's a steep learning curve -- is the question."
Battles in the Senate over climate bill language will be intense, and natural gas lags behind its competitors in the race to sway lawmakers.
"Much of what is going on is an industry feeling left out of the party and hoping to get more goodies for itself in the Senate bill," Steven Hayward, fellow at the American Enterprise Institute, a conservative think tank, said of natural gas.
Coal lobbyists have been talking to senators and aides for months, with their contacts becoming more frequent since the House bill passed. Coal lobbyists want to slow down the pace of the House measure's plan to cap greenhouse gas emissions and make businesses buy allowances for those emissions.
Natural gas also will have to compete against the utility industry, which has been lobbying heavily on energy legislation. While they represent natural gas and coal, utilities have big reasons to favor coal.
Electric utilities used coal for 59 percent of their power generation in 2007, while natural gas was used 13 percent of the time, according to the Energy Information Administration. Coal has been less expensive, making it more profitable for utilities to use as a fuel source.
Lobbying by utility interests so far has dwarfed competitors. In the first quarter of this year, utilities spent $35.1 million on lobbying. The natural gas industry spent less than a tenth of that, $3.3 million. Of the top 10 industries with a stake in climate legislation, natural gas put the least money into lobbying in the first quarter, according to a recent E&E analysis.
"As a whole, we're not very sophisticated in terms of public relations, and we need to be," Julander said. "We need to grow up and get in this game. No one is going to give us anything, even though we're the best for the environment."
'Coal Preservation Act'
Coal and natural gas are the top fuels used to make electricity in the United States. Natural gas emits about half the carbon dioxide, the principal greenhouse gas, that coal does for the same amount of energy produced. Natural gas executives and others at the Denver conference argued that while the House-passed legislation strives to reduce carbon emissions, it insulates coal in a way that will hurt lower-emitting natural gas.
Analysts agree that the bill crafted by Reps. Henry Waxman (D-Calif.) and Ed Markey (D-Mass.) helps coal.
"Coal did very well in Waxman-Markey," said AEI's Hayward, who added that the legislation could be called the "Sleight-Of-Hand Coal Preservation Act."
"It is so well-established in so many industrial states, and replacing it with another source, even natural gas, would cause a serious increase in utility rates, which no politician wants their fingerprints on," said Hayward, who in general dislikes the bill.
A spokesman for a trade group representing coal interests said the bill is structured to lower carbon emissions while still protecting consumers from higher electricity costs.
"The reality is, natural gas is a higher-priced fuel. It's a less domestically available fuel," said Joe Lucas, spokesman for American Coalition for Clean Coal Electricity. Language in the bill helping utilities that use coal "is a way of reducing the consumer's end price."
In the early years of climate regulation that charges for carbon emissions, the government would give away 85 percent of the carbon emission allowances and auction the remaining 15 percent.
http://www.nytimes.com/gwire/2009/07/13/13greenwire-at-center-ring-in-senate-climate-debate-coal-v-32201.html
Monday, July 13, 2009
Natural Gas Revenue Comes to Turkmenistan
TURKMENBASHI, Turkmenistan -- Four white-marble hotels opened here in June on a spit of sand by a landlocked sea - the beginnings of what is billed as Central Asia's answer to Las Vegas, an opulent $5 billion oasis of seaside villas, casinos, an artificial island and a ski center.
The resort-to-be stands out in this arid country the size of California, where camels clop down dirt roads and bedraggled Soviet-era apartment blocks doze in the blistering desert heat. Yet Turkmenistan also sits atop the world's fifth-largest reserves of natural gas, and is rapidly emerging as a key player in global energy markets.
Its secretive, autocratic government is using some of its more than $7 billion in annual gas revenues to build the pleasure park, called Avaza. Officials say they hope to attract high-rolling foreign tourists and open up their country, long sealed off from most of the outside world.
"Coming to our country has always been a problem for foreigners," Murat Kariyev, the country's elections commission chairman, told The Associated Press. He called Avaza "the world's window on Turkmenistan."
The world's biggest consumers of energy want to do more than peek through the window at Turkmenistan - they want to barge through the door. The U.S., Europe, China, Russia and Iran are all jostling for greater access to the country's mammoth natural gas fields, which could contain more than 26 trillion cubic yards (20 trillion cubic meters) of natural gas. That's enough to supply Europe with gas for the next 66 years.
The European Union and the United States see Turkmenistan's President Gurbanguli Berdymukhamedov, who took power 2 1/2 years ago, as a potential ally in their efforts to break reliance on Russia for natural gas.
But Russia, Turkmenistan's chief energy partner, is fighting a rearguard action to keep its near monopoly on the purchase of Turkmen gas. In 2008, Russia's state-controlled energy giant Gazprom paid Turkmenistan $7 billion for gas that Russia resold to Europe, according to Global Witness, a London-based watchdog group.
China in turn has moved boldly to challenge Russia, cutting its own energy deal, which includes a $4 billion loan. Beijing plans to begin tapping a major natural gas field in eastern Turkmenistan when a new pipeline is finished as early as this year.
Courted from all sides, sitting on vast wealth, Turkmenistan's regime faces stark choices: to open its doors or live in continued isolation, to push for reform or renew repression.
The Avaza resort on the Caspian Sea symbolizes some of these conflicts. It is designed to appeal to the sophisticated business traveler. Yet during opening ceremonies, the white marble hotels were decorated Soviet-style with gigantic pictures of President Berdymukhamedov, and a huge television screen beamed down a picture of the president's face.
Few visitors are expected at the 50-square kilometer (19-square mile) complex, part of a special visa zone, until a new international airport is completed later this year. Even then, they may not see more than a restricted patch of the country or have much contact with ordinary people.
Critics say the resort is just another example of Turkmenistan's propensity for huge and impractical building programs, shown clearly under former president Saparmurat Niyazov, and could wind up a sinkhole for billions of dollars in gas revenues.
http://www.washingtonpost.com/wp-dyn/content/article/2009/07/12/AR2009071201064.html
The resort-to-be stands out in this arid country the size of California, where camels clop down dirt roads and bedraggled Soviet-era apartment blocks doze in the blistering desert heat. Yet Turkmenistan also sits atop the world's fifth-largest reserves of natural gas, and is rapidly emerging as a key player in global energy markets.
Its secretive, autocratic government is using some of its more than $7 billion in annual gas revenues to build the pleasure park, called Avaza. Officials say they hope to attract high-rolling foreign tourists and open up their country, long sealed off from most of the outside world.
"Coming to our country has always been a problem for foreigners," Murat Kariyev, the country's elections commission chairman, told The Associated Press. He called Avaza "the world's window on Turkmenistan."
The world's biggest consumers of energy want to do more than peek through the window at Turkmenistan - they want to barge through the door. The U.S., Europe, China, Russia and Iran are all jostling for greater access to the country's mammoth natural gas fields, which could contain more than 26 trillion cubic yards (20 trillion cubic meters) of natural gas. That's enough to supply Europe with gas for the next 66 years.
The European Union and the United States see Turkmenistan's President Gurbanguli Berdymukhamedov, who took power 2 1/2 years ago, as a potential ally in their efforts to break reliance on Russia for natural gas.
But Russia, Turkmenistan's chief energy partner, is fighting a rearguard action to keep its near monopoly on the purchase of Turkmen gas. In 2008, Russia's state-controlled energy giant Gazprom paid Turkmenistan $7 billion for gas that Russia resold to Europe, according to Global Witness, a London-based watchdog group.
China in turn has moved boldly to challenge Russia, cutting its own energy deal, which includes a $4 billion loan. Beijing plans to begin tapping a major natural gas field in eastern Turkmenistan when a new pipeline is finished as early as this year.
Courted from all sides, sitting on vast wealth, Turkmenistan's regime faces stark choices: to open its doors or live in continued isolation, to push for reform or renew repression.
The Avaza resort on the Caspian Sea symbolizes some of these conflicts. It is designed to appeal to the sophisticated business traveler. Yet during opening ceremonies, the white marble hotels were decorated Soviet-style with gigantic pictures of President Berdymukhamedov, and a huge television screen beamed down a picture of the president's face.
Few visitors are expected at the 50-square kilometer (19-square mile) complex, part of a special visa zone, until a new international airport is completed later this year. Even then, they may not see more than a restricted patch of the country or have much contact with ordinary people.
Critics say the resort is just another example of Turkmenistan's propensity for huge and impractical building programs, shown clearly under former president Saparmurat Niyazov, and could wind up a sinkhole for billions of dollars in gas revenues.
http://www.washingtonpost.com/wp-dyn/content/article/2009/07/12/AR2009071201064.html
Sunday, July 12, 2009
Natural Gas Piceance Basin Ramping Up for Drilling
RIFLE, Colo. — Oil and gas producers have known for decades that a massive bounty of natural gas lies beneath western Colorado's mountains. Getting at it, however, can be costly and complicated.
With a potential gain of 1 billion cubic feet per day of output from its leased land in the deepest part of the gas-rich Piceance Basin — which would be about 2 percent of all U.S. gas production — Exxon Mobil Corp. spent the last decade perfecting a way to drill less for more gas.
Now, the Irving-based behemoth is ramping up its Piceance project with more drilling and with new, largely automated gas gathering, treatment and monitoring facilities.
Armed with the financial heft to shrug off low natural gas prices that have prompted other Piceance producers to move out or slow down, Exxon Mobil is running seven rigs, five more than two years ago.
“Now that we have this level of rigs, we can drive down costs,” said Jim Branch, Exxon Mobil's Piceance Project executive.
The Piceance is a bowl-shaped underground basin that covers 6,000 square miles in five counties on both sides of the Colorado River.
Its allure isn't new. Southern Union Gas drilled the first well there in the mid-1950s.
The federal government exploded nuclear bombs underground there in the late 1960s and early 1970s, hoping to unleash natural gas and to demonstrate the bombs had peacetime uses. The explosions yielded no gas other than some of the radioactive kind, and public opposition squelched the blasts. So, Piceance activity was light until recent years, when technological advances caught up with the challenges of getting at so-called “tight gas” trapped in pockets of concrete-like sandstone in remote mountain areas.
Despite natural gas prices that have fallen below $3.50 per million British thermal units from last year's highs of $13, Exxon Mobil is banking on the Piceance for years to come. The company has leased about 300,000 acres of mostly federal land that Exxon Mobil says could contain 45 trillion cubic feet of gas. That's about twice the amount of gas consumed in the U.S. each year, according to the U.S. Energy Information Administration.
“That potential is huge,” said Fadel Gheit, an analyst with Oppenheimer & Co. “They are doing it in the methodical Exxon way. Exxon is very bullish on natural gas globally, not only in the U.S., and they are putting their money where their mouth is.”
‘Elegant ballet'
Exxon Mobil spent a decade tinkering with technology used to extract gas elsewhere to adapt it to the Piceance. The company came up with a way to drill deep, then blast holes in the pipe next to pockets of gas. A mixture of chemicals and water shoot into the well at high pressure to crack open the rock, while sand that's mixed in holds the fissure open so gas can flow.
The process involves repeated fractures in up to 50 zones that contain gas pockets on the way back up the well, like opening an elevator door on various floors, to maximize gas flowing from each well.
“We use the term ‘elegant ballet' because we can actually do multiple wells now,” Branch said. “The key to improving the cost is to keep this equipment working constantly.”
That process, combined with directional drilling that deviates from a straight vertical line, means Exxon Mobil can drill up to 20 wells per site. That translates to fewer rigs sharing space with the basin's mountains, pinyon pines, sagebrush and grazing cattle.
The company says the method dramatically cuts operational costs. Exxon Mobil won't disclose the Piceance project costs, except to say that it's part of the company's plan to spend $125 billion on projects over five years, including $29 billion this year.
Exxon Mobil is among many producers in the Piceance. Others include EnCana, Williams, XTO Energy and Chevron.
Williams tried Exxon Mobil's technology in 2006 but found no cost benefits above what the company was already doing, spokesman Jeff Pounds said.
Exxon Mobil began increasing its Piceance presence two years ago. At the peak of construction, 600 workers were on the payroll. Now, about 60 employees run the operations, mostly from a control center, while contractors do the heavy lifting with drilling and seismic imaging.
Falling gas prices
Work in the area has slowed since natural gas prices dropped.
“We had 105 rigs in the basin last year; now, there are 25,” said Shawn Brennan, manager of Houston-based Enterprise Products Partners' new gas treating plant in the basin.
Besides moving gas, Brennan said, the company's Piceance operations extract up to 70,000 barrels a day of natural gas liquids, such as propane, butane and ethane, which can be sold outright or used in processing at refineries and chemical plants.
“That's a lot of diversity to weather the markets as they are now,” he said.
Exxon Mobil faced some lingering ill will when establishing its gas operations. In the early 1980s, the company had a major oil shale operation in the Piceance. That decade's oil bust prompted an abrupt pullout, throwing the Rifle-area economy into a tailspin for years.
To make itself more welcome, the company donated $500,000 to help pay for a new helicopter ambulance pad at a hospital in Grand Junction.
Co-existing
Other community service outreach efforts include an academy for math and science teachers in area public schools and an annual sheepdog championship competition.
“We were certainly mindful of that history,” Branch said. “I know there is some legacy there, but it has not complicated our work here.”
For the ranchers in the Piceance, it's sometimes a challenge to co-exist.
Exxon Mobil and some other producers try to limit traffic by busing workers in to work and having them live on site for 14 days, like offshore crews. The companies replant grass and trees after clearing right of way for pipelines, and cattle guards prevent free-roaming livestock from wandering too close to plants.
Larry Robinson, 63, a third-generation rancher, said he sees evidence of environmental sensitivity, but there's no way to pretend the producers aren't there.
“The solitude's gone, and we're getting more and more wells and more and more pipelines, more and more compressors,” Robinson said. “It isn't like it used to be for us, and I don't think it will ever be the same.”
kristen.hays@chron.com
http://www.chron.com/disp/story.mpl/business/6525226.html
With a potential gain of 1 billion cubic feet per day of output from its leased land in the deepest part of the gas-rich Piceance Basin — which would be about 2 percent of all U.S. gas production — Exxon Mobil Corp. spent the last decade perfecting a way to drill less for more gas.
Now, the Irving-based behemoth is ramping up its Piceance project with more drilling and with new, largely automated gas gathering, treatment and monitoring facilities.
Armed with the financial heft to shrug off low natural gas prices that have prompted other Piceance producers to move out or slow down, Exxon Mobil is running seven rigs, five more than two years ago.
“Now that we have this level of rigs, we can drive down costs,” said Jim Branch, Exxon Mobil's Piceance Project executive.
The Piceance is a bowl-shaped underground basin that covers 6,000 square miles in five counties on both sides of the Colorado River.
Its allure isn't new. Southern Union Gas drilled the first well there in the mid-1950s.
The federal government exploded nuclear bombs underground there in the late 1960s and early 1970s, hoping to unleash natural gas and to demonstrate the bombs had peacetime uses. The explosions yielded no gas other than some of the radioactive kind, and public opposition squelched the blasts. So, Piceance activity was light until recent years, when technological advances caught up with the challenges of getting at so-called “tight gas” trapped in pockets of concrete-like sandstone in remote mountain areas.
Despite natural gas prices that have fallen below $3.50 per million British thermal units from last year's highs of $13, Exxon Mobil is banking on the Piceance for years to come. The company has leased about 300,000 acres of mostly federal land that Exxon Mobil says could contain 45 trillion cubic feet of gas. That's about twice the amount of gas consumed in the U.S. each year, according to the U.S. Energy Information Administration.
“That potential is huge,” said Fadel Gheit, an analyst with Oppenheimer & Co. “They are doing it in the methodical Exxon way. Exxon is very bullish on natural gas globally, not only in the U.S., and they are putting their money where their mouth is.”
‘Elegant ballet'
Exxon Mobil spent a decade tinkering with technology used to extract gas elsewhere to adapt it to the Piceance. The company came up with a way to drill deep, then blast holes in the pipe next to pockets of gas. A mixture of chemicals and water shoot into the well at high pressure to crack open the rock, while sand that's mixed in holds the fissure open so gas can flow.
The process involves repeated fractures in up to 50 zones that contain gas pockets on the way back up the well, like opening an elevator door on various floors, to maximize gas flowing from each well.
“We use the term ‘elegant ballet' because we can actually do multiple wells now,” Branch said. “The key to improving the cost is to keep this equipment working constantly.”
That process, combined with directional drilling that deviates from a straight vertical line, means Exxon Mobil can drill up to 20 wells per site. That translates to fewer rigs sharing space with the basin's mountains, pinyon pines, sagebrush and grazing cattle.
The company says the method dramatically cuts operational costs. Exxon Mobil won't disclose the Piceance project costs, except to say that it's part of the company's plan to spend $125 billion on projects over five years, including $29 billion this year.
Exxon Mobil is among many producers in the Piceance. Others include EnCana, Williams, XTO Energy and Chevron.
Williams tried Exxon Mobil's technology in 2006 but found no cost benefits above what the company was already doing, spokesman Jeff Pounds said.
Exxon Mobil began increasing its Piceance presence two years ago. At the peak of construction, 600 workers were on the payroll. Now, about 60 employees run the operations, mostly from a control center, while contractors do the heavy lifting with drilling and seismic imaging.
Falling gas prices
Work in the area has slowed since natural gas prices dropped.
“We had 105 rigs in the basin last year; now, there are 25,” said Shawn Brennan, manager of Houston-based Enterprise Products Partners' new gas treating plant in the basin.
Besides moving gas, Brennan said, the company's Piceance operations extract up to 70,000 barrels a day of natural gas liquids, such as propane, butane and ethane, which can be sold outright or used in processing at refineries and chemical plants.
“That's a lot of diversity to weather the markets as they are now,” he said.
Exxon Mobil faced some lingering ill will when establishing its gas operations. In the early 1980s, the company had a major oil shale operation in the Piceance. That decade's oil bust prompted an abrupt pullout, throwing the Rifle-area economy into a tailspin for years.
To make itself more welcome, the company donated $500,000 to help pay for a new helicopter ambulance pad at a hospital in Grand Junction.
Co-existing
Other community service outreach efforts include an academy for math and science teachers in area public schools and an annual sheepdog championship competition.
“We were certainly mindful of that history,” Branch said. “I know there is some legacy there, but it has not complicated our work here.”
For the ranchers in the Piceance, it's sometimes a challenge to co-exist.
Exxon Mobil and some other producers try to limit traffic by busing workers in to work and having them live on site for 14 days, like offshore crews. The companies replant grass and trees after clearing right of way for pipelines, and cattle guards prevent free-roaming livestock from wandering too close to plants.
Larry Robinson, 63, a third-generation rancher, said he sees evidence of environmental sensitivity, but there's no way to pretend the producers aren't there.
“The solitude's gone, and we're getting more and more wells and more and more pipelines, more and more compressors,” Robinson said. “It isn't like it used to be for us, and I don't think it will ever be the same.”
kristen.hays@chron.com
http://www.chron.com/disp/story.mpl/business/6525226.html
Saturday, July 11, 2009
Colorado Governor Supportive of Natural Gas Projects
DENVER -- Colorado Gov. Bill Ritter, who has made promoting renewable energy a cornerstone of his administration, on Thursday called natural gas "a mission-critical fuel" that is essential to the state and nation's economy.
"Natural gas is a vital part of the new energy economy, a permanent part of the new energy economy, not a bridge fuel, not a transition fuel, but a mission-critical fuel," Ritter told a crowd of industry officials at the Colorado Oil and Gas Association's annual conference in Denver.Ritter and the Denver-based trade group have frequently been at odds as his administration promoted stricter oil and gas regulations and a "new energy economy" that includes attracting renewable energy companies to Colorado.
The association filed a lawsuit this spring to overturn new regulations that implemented two 2007 laws requiring more weight be given to the environment, wildlife and public health and safety when oil and gas development is considered.
Association spokesman Nate Strauch called Ritter's speech "eye-opening." He said industry representatives hope it signals a narrowing of differences with the governor.
"I think the industry is just very encouraged by what it heard today," Strauch said.Industry officials have assailed Colorado's new rules, which took effect April 1, as some of the most burdensome in the country. They said the rules have contributed to the slowdown in the state's oil and gas production.
A state commission that regulates oil and gas development was also overhauled to include more members outside the industry.
State regulators and the rules' proponents, including environmental, hunting and angling groups, said the recession, low natural gas prices and tight credit are behind the decline in production, not the regulations.
Even before Thursday's speech, Ritter had made overtures to the industry. He has urged federal officials to quickly certify proposed natural gas pipelines, saying a lack of capacity results in lower gas prices for area producers.
In May, Ritter wrote to congressional leaders to ask them to reconsider ending a tax break for the oil and gas industry, saying it could discourage energy development. His administration is also applying for a $10 million federal grant to expand use of compressed natural gas for transportation fuel in Colorado.
Ritter said during his speech Thursday that he has asked U.S. Rep. Diana DeGette, a Democrat from Denver, to consider a comprehensive study of the drilling technique hydraulic fracturing before "jumping directly to a new and potentially intrusive regulatory program."
DeGette has introduced a bill that would regulate hydraulic fracturing, also called "fracking," under the federal Safe Drinking Water Act. The 2005 energy bill exempted the process from regulation under that law.
The process involves injecting liquids, sand and chemicals underground to force open channels in tight sand and rock formations so that oil and gas will flow. Landowners and groups supporting DeGette's bill say fracking threatens groundwater, a claim industry groups dismiss as unsubstantiated.
Copyright 2009 Associated Press. All rights reserved. This material may not be published broadcast, rewritten, or redistributed http://www.forbes.com/feeds/ap/2009/07/10/ap6641216.html
"Natural gas is a vital part of the new energy economy, a permanent part of the new energy economy, not a bridge fuel, not a transition fuel, but a mission-critical fuel," Ritter told a crowd of industry officials at the Colorado Oil and Gas Association's annual conference in Denver.Ritter and the Denver-based trade group have frequently been at odds as his administration promoted stricter oil and gas regulations and a "new energy economy" that includes attracting renewable energy companies to Colorado.
The association filed a lawsuit this spring to overturn new regulations that implemented two 2007 laws requiring more weight be given to the environment, wildlife and public health and safety when oil and gas development is considered.
Association spokesman Nate Strauch called Ritter's speech "eye-opening." He said industry representatives hope it signals a narrowing of differences with the governor.
"I think the industry is just very encouraged by what it heard today," Strauch said.Industry officials have assailed Colorado's new rules, which took effect April 1, as some of the most burdensome in the country. They said the rules have contributed to the slowdown in the state's oil and gas production.
A state commission that regulates oil and gas development was also overhauled to include more members outside the industry.
State regulators and the rules' proponents, including environmental, hunting and angling groups, said the recession, low natural gas prices and tight credit are behind the decline in production, not the regulations.
Even before Thursday's speech, Ritter had made overtures to the industry. He has urged federal officials to quickly certify proposed natural gas pipelines, saying a lack of capacity results in lower gas prices for area producers.
In May, Ritter wrote to congressional leaders to ask them to reconsider ending a tax break for the oil and gas industry, saying it could discourage energy development. His administration is also applying for a $10 million federal grant to expand use of compressed natural gas for transportation fuel in Colorado.
Ritter said during his speech Thursday that he has asked U.S. Rep. Diana DeGette, a Democrat from Denver, to consider a comprehensive study of the drilling technique hydraulic fracturing before "jumping directly to a new and potentially intrusive regulatory program."
DeGette has introduced a bill that would regulate hydraulic fracturing, also called "fracking," under the federal Safe Drinking Water Act. The 2005 energy bill exempted the process from regulation under that law.
The process involves injecting liquids, sand and chemicals underground to force open channels in tight sand and rock formations so that oil and gas will flow. Landowners and groups supporting DeGette's bill say fracking threatens groundwater, a claim industry groups dismiss as unsubstantiated.
Copyright 2009 Associated Press. All rights reserved. This material may not be published broadcast, rewritten, or redistributed http://www.forbes.com/feeds/ap/2009/07/10/ap6641216.html
Friday, July 10, 2009
Hatch Joins TBoone Pushing Natural Gas
Updated: 07/09/2009 07:42:24 AM MDT
Washington » Sen. Orrin Hatch teamed up with T. Boone Pickens on Wednesday to promote legislation that would boost natural-gas-fueled vehicles through tax incentives.
The Utah Republican and the Texas oilman -- along with Senate Majority Leader Harry Reid and Democratic Sen. Bob Menendez of New Jersey -- say the measure could help curb pollution and create American energy independence at the same time.
Hatch in 2005 sponsored the CLEAR ACT (Clean Efficient Automobiles Resulting from Advanced Car Technologies), which promoted the manufacture and purchase of hybrid cars.
"I've been very pleased with the growth and use of hybrid-electric vehicles in this country since the passage of the Clear Act," Hatch said at a Capitol news conference. "But I've been less pleased with the growth of natural gas as a transportation fuel. I believe strongly that we need an extra push to spur on the greater use of natural gas, to get more natural gas vehicles on our roads."
The bill would extend for 10 years tax credits for buying natural-gas powered vehicles, for installing refueling outlets and for converting regular gas-fueled cars to natural gas. It also would allow states and local governments to bond to finance natural-gas vehicle projects, and to allow new natural gas vehicle manufacturing plants to write off 100 percent of the costs to build the plant.
Pickens, who has spent $60 million to promote a shift to a wind-solar-natural-gas-run America, said the security of the nation is put at risk by continuing to spend billions on oil from "less-than-friendly" countries.
"The only way you can win this battle is on your own resources," Pickens said, noting that America has the cheapest and most abundant sources of natural gas in the world.
Reid, D-Nev., said natural-gas vehicles could save consumers money and help the environment at the same time.
"We must get serious about using cleaner burning natural gas and renewable energy, and this legislation is a strong step in the right direction," Reid said.
tburr@sltrib.com
http://www.sltrib.com/business/ci_12787175
Washington » Sen. Orrin Hatch teamed up with T. Boone Pickens on Wednesday to promote legislation that would boost natural-gas-fueled vehicles through tax incentives.
The Utah Republican and the Texas oilman -- along with Senate Majority Leader Harry Reid and Democratic Sen. Bob Menendez of New Jersey -- say the measure could help curb pollution and create American energy independence at the same time.
Hatch in 2005 sponsored the CLEAR ACT (Clean Efficient Automobiles Resulting from Advanced Car Technologies), which promoted the manufacture and purchase of hybrid cars.
"I've been very pleased with the growth and use of hybrid-electric vehicles in this country since the passage of the Clear Act," Hatch said at a Capitol news conference. "But I've been less pleased with the growth of natural gas as a transportation fuel. I believe strongly that we need an extra push to spur on the greater use of natural gas, to get more natural gas vehicles on our roads."
The bill would extend for 10 years tax credits for buying natural-gas powered vehicles, for installing refueling outlets and for converting regular gas-fueled cars to natural gas. It also would allow states and local governments to bond to finance natural-gas vehicle projects, and to allow new natural gas vehicle manufacturing plants to write off 100 percent of the costs to build the plant.
Pickens, who has spent $60 million to promote a shift to a wind-solar-natural-gas-run America, said the security of the nation is put at risk by continuing to spend billions on oil from "less-than-friendly" countries.
"The only way you can win this battle is on your own resources," Pickens said, noting that America has the cheapest and most abundant sources of natural gas in the world.
Reid, D-Nev., said natural-gas vehicles could save consumers money and help the environment at the same time.
"We must get serious about using cleaner burning natural gas and renewable energy, and this legislation is a strong step in the right direction," Reid said.
tburr@sltrib.com
http://www.sltrib.com/business/ci_12787175
Thursday, July 9, 2009
U.S. Congress Advancing Natural Gas
WASHINGTON (Reuters) - U.S. lawmakers on Wednesday unveiled legislation aimed at helping the nation wean itself off foreign oil by providing financial incentives for the use of vehicles fueled by natural gas.
Sponsored by Democratic Senator Robert Menendez, the bill would extend for 10 years tax credits for purchasing vehicles that run on natural gas and installing natural gas refueling stations.
"We saw last summer how the wild fluctuations in oil prices helped to wreck our economy, and we've seen how pollutants from dirty fuels are wrecking our planet," Menendez said at a press conference.
He added that the recent economic downturn also had "shined a spotlight on the urgent need for alternative, cleaner and cheaper sources of energy that we don't have to import."
The legislation is backed by Senate Majority Leader Harry Reid and Republican Senator Orrin Hatch.
Recent advances in technology have led to a natural gas production boom in the United States, after years of stagnant growth in the sector.
"We have much more natural gas than we thought we did just a few years ago," Hatch said at the press conference.
He said there were enough reserves to "significantly increase" the use of natural gas as a transportation fuel.
In addition to extending the tax breaks, the bill would also raise the tax credit caps for consumers who buy natural gas-fueled vehicles and provide tax breaks for manufacturers of those vehicles. The bill would also provide grants for the development of light- and heavy-duty natural gas engines.
Menendez said he may be able to attach his bill to energy and climate change packages the Senate is set to consider some time this year.
(Editing by Walter Bagley)
Sponsored by Democratic Senator Robert Menendez, the bill would extend for 10 years tax credits for purchasing vehicles that run on natural gas and installing natural gas refueling stations.
"We saw last summer how the wild fluctuations in oil prices helped to wreck our economy, and we've seen how pollutants from dirty fuels are wrecking our planet," Menendez said at a press conference.
He added that the recent economic downturn also had "shined a spotlight on the urgent need for alternative, cleaner and cheaper sources of energy that we don't have to import."
The legislation is backed by Senate Majority Leader Harry Reid and Republican Senator Orrin Hatch.
Recent advances in technology have led to a natural gas production boom in the United States, after years of stagnant growth in the sector.
"We have much more natural gas than we thought we did just a few years ago," Hatch said at the press conference.
He said there were enough reserves to "significantly increase" the use of natural gas as a transportation fuel.
In addition to extending the tax breaks, the bill would also raise the tax credit caps for consumers who buy natural gas-fueled vehicles and provide tax breaks for manufacturers of those vehicles. The bill would also provide grants for the development of light- and heavy-duty natural gas engines.
Menendez said he may be able to attach his bill to energy and climate change packages the Senate is set to consider some time this year.
(Editing by Walter Bagley)
Wednesday, July 8, 2009
TBoone Still Touting Natural Gas Long Term for USA
July 7 (Bloomberg) -- T. Boone Pickens, founder and chairman of Dallas-based BP Capital LLC, said oil prices will match last year’s record $147 a barrel in three years as producers fail to increase output.
“We’ll be flat at 85 million barrels a year,” Pickens said in an interview. “By 2013 we’re going to see a decline in production. In 10 years we’ll be at $300 a barrel.”
Pickens, 81, one year ago started a $60 million promotion for a national energy plan that relies on domestically produced natural gas to cut U.S. dependence on foreign oil. Without a switch to gas, the U.S. will be spending $2 trillion a year importing oil, he said.
“The problem is we don’t have the oil,” Pickens said. “And we’ve got gas coming out our ears.”
Crude oil futures for August delivery today fell $1.12, or 1.7 percent, to $62.93 a barrel on the New York Mercantile Exchange. The price has gained 41 percent this year.
Oil is not going to get any less expensive relative to natural gas, Pickens said. He said gas needs no refining and emits 50 percent less pollution than gasoline.
His plan has received some support in Congress, said Graham Mattison, an analyst at Lazard Capital Markets in New York.
“Political support for the natural gas vehicle industry continues to build,” Mattison said. A House bill would double some natural-gas vehicle tax credits and double the amount stations would get to install pumps for the fuel, he said. The Senate may consider similar legislation tomorrow, he said.
To contact the reporter on this story: Christopher Martin in New York at cmartin11@bloomberg.net.
“We’ll be flat at 85 million barrels a year,” Pickens said in an interview. “By 2013 we’re going to see a decline in production. In 10 years we’ll be at $300 a barrel.”
Pickens, 81, one year ago started a $60 million promotion for a national energy plan that relies on domestically produced natural gas to cut U.S. dependence on foreign oil. Without a switch to gas, the U.S. will be spending $2 trillion a year importing oil, he said.
“The problem is we don’t have the oil,” Pickens said. “And we’ve got gas coming out our ears.”
Crude oil futures for August delivery today fell $1.12, or 1.7 percent, to $62.93 a barrel on the New York Mercantile Exchange. The price has gained 41 percent this year.
Oil is not going to get any less expensive relative to natural gas, Pickens said. He said gas needs no refining and emits 50 percent less pollution than gasoline.
His plan has received some support in Congress, said Graham Mattison, an analyst at Lazard Capital Markets in New York.
“Political support for the natural gas vehicle industry continues to build,” Mattison said. A House bill would double some natural-gas vehicle tax credits and double the amount stations would get to install pumps for the fuel, he said. The Senate may consider similar legislation tomorrow, he said.
To contact the reporter on this story: Christopher Martin in New York at cmartin11@bloomberg.net.
Tuesday, July 7, 2009
Natural Gas Canadian with Spanish Flair
CALGARY, Alberta, July 6 (Reuters) - Spanish natural-gas distributor Gas Natural (GAS.MC) agreed on Monday to take 30 percent of the output from a planned liquefied natural-gas facility on Canada's West Coast and may buy a stake in the operation, the proposed plant's operator said in a release.
Closely held Kitimat LNG Inc said it has signed a memorandum of understanding with Gas Natural, which will see the Spanish firm acquire up to 1.6 million tonnes of LNG a year from the Kitimat liquefaction operation for 20 years.
Gas Natural also has an option to take an equity stake in the LNG terminal.
The agreement is the second major supply deal for the Kitimat operation in just over a month. In early June it signed memorandum of understanding with Korea Gas Corp under which Kogas would acquire 2 million tonnes of LNG a year from the terminal for 20 years, with the option to acquire an equity stake in the plant.
The proposed Kitimat plant, on a port in northern British Columbia, would have the capacity to export 3.5 million to 5 million tonnes of super-cooled gas a year, the equivalent of four or five cargoes a month.
Kitimat, which was originally supposed to be an import project, now intends to export LNG from Western Canada to markets across the Pacific in Asia by 2013.
Gas Natural supplies natural gas to 11 million customers in Spain, France, Italy and Latin America, and has a generating arm producing electricity in Spain, Mexico and Puerto Rico.
It is also in a joint venture with Repsol (REP.MC), which operates a fleet of LNG carriers. (Reporting by Scott Haggett; editing by Rob Wilson)
Closely held Kitimat LNG Inc said it has signed a memorandum of understanding with Gas Natural, which will see the Spanish firm acquire up to 1.6 million tonnes of LNG a year from the Kitimat liquefaction operation for 20 years.
Gas Natural also has an option to take an equity stake in the LNG terminal.
The agreement is the second major supply deal for the Kitimat operation in just over a month. In early June it signed memorandum of understanding with Korea Gas Corp under which Kogas would acquire 2 million tonnes of LNG a year from the terminal for 20 years, with the option to acquire an equity stake in the plant.
The proposed Kitimat plant, on a port in northern British Columbia, would have the capacity to export 3.5 million to 5 million tonnes of super-cooled gas a year, the equivalent of four or five cargoes a month.
Kitimat, which was originally supposed to be an import project, now intends to export LNG from Western Canada to markets across the Pacific in Asia by 2013.
Gas Natural supplies natural gas to 11 million customers in Spain, France, Italy and Latin America, and has a generating arm producing electricity in Spain, Mexico and Puerto Rico.
It is also in a joint venture with Repsol (REP.MC), which operates a fleet of LNG carriers. (Reporting by Scott Haggett; editing by Rob Wilson)
Subscribe to:
Posts (Atom)