By Moming Zhou
Last update: 10:37 a.m. EST Feb. 26, 2009
Comments: 5
NEW YORK (MarketWatch) -- U.S. natural gas inventories fell by 101 billion cubic feet in the week ended Feb. 20, the Energy Information Administration reported Thursday. Analysts at IHS Global Insight had expected a withdrawal of 145 billion cubic feet. At 1,895 billion cubic feet, stocks were 233 billion cubic feet higher than last year at this time and 199 billion cubic feet above the five-year average. On the New York Mercantile Exchange, natural gas for April delivery added 1.1% to $4.073 per million British thermal units
Saturday, February 28, 2009
Friday, February 27, 2009
Keep Your Eye on Natural Gas Companies
By David Lee Smith
February 26, 2009
www.fool.com - The Motley Fool
Crude oil, with its whipsaw pricing during 2008, clearly has received most of the attention given to energy over the past year. Indeed, who would have expected its per-barrel price to fluctuate from more than $145 in July to a winter levy below $35?
But lest you think that natural gas is taking a decided and irrevocable second place to its crude sibling, you need to know about the gas goings-on in a couple of areas of the world. In the U.S., for instance, a group of gas producers -- including Chesapeake (NYSE: CHK), the nation's top natural gas producer, and Devon (NYSE: DVN), its Oklahoma City neighbor -- are in the process of joining other independent producers in forming a lobby group aimed at promoting natural gas for power generation and transportation.
The difficulty in the current U.S. natural gas market -- as opposed to as recently as a couple of years ago -- is too much supply chasing too little demand. On the supply side, volumes have been pushed up by the discovery of vast new quantities of gas in tight rocks (shale). These discoveries have been in places like the Barnett Shale of North Texas, as well as the giant Haynesville Shale of Texas and Louisiana, where both Petrohawk (NYSE: HK) and EXCO Resources (NYSE: XCO) recently found gushers.
At the same time, the now nearly worldwide pullback in demand from such slowing industries as petrochemicals has precipitated a natural gas glut. The result has been a near 70% decline in gas prices just since July.
And then there's Australia, where a group of sizable companies, including Royal Dutch Shell (NYSE: RDS-A) and ConocoPhillips (NYSE: COP), have become active in coal-bed methane plays. The target: natural gas trapped within coal seams, primarily in Queensland in the northeastern part of the nation. One of the many benefits to coal-bed methane -- also known as coal-seam gas -- is that it is far greener and cleaner-burning than fossil fuels.
So while much of the world continues to be fixated on the deepwater oil discoveries offshore Brazil and Eastern Russia, for example, I urge my Foolish friends to keep your eyes glued to the stronger gas producers. Two of the names I've already mentioned are Chesapeake and Devon. I fervently believe that within the next couple of years, the world of gas will pick up significantly. On that basis, I'd recommend that you remain represented in this slow-moving -- but promising -- sector.
Both Chesapeake and Devon have received five-star ratings from Motley Fool CAPS players. Why not weigh in on your feelings about the two companies?
February 26, 2009
www.fool.com - The Motley Fool
Crude oil, with its whipsaw pricing during 2008, clearly has received most of the attention given to energy over the past year. Indeed, who would have expected its per-barrel price to fluctuate from more than $145 in July to a winter levy below $35?
But lest you think that natural gas is taking a decided and irrevocable second place to its crude sibling, you need to know about the gas goings-on in a couple of areas of the world. In the U.S., for instance, a group of gas producers -- including Chesapeake (NYSE: CHK), the nation's top natural gas producer, and Devon (NYSE: DVN), its Oklahoma City neighbor -- are in the process of joining other independent producers in forming a lobby group aimed at promoting natural gas for power generation and transportation.
The difficulty in the current U.S. natural gas market -- as opposed to as recently as a couple of years ago -- is too much supply chasing too little demand. On the supply side, volumes have been pushed up by the discovery of vast new quantities of gas in tight rocks (shale). These discoveries have been in places like the Barnett Shale of North Texas, as well as the giant Haynesville Shale of Texas and Louisiana, where both Petrohawk (NYSE: HK) and EXCO Resources (NYSE: XCO) recently found gushers.
At the same time, the now nearly worldwide pullback in demand from such slowing industries as petrochemicals has precipitated a natural gas glut. The result has been a near 70% decline in gas prices just since July.
And then there's Australia, where a group of sizable companies, including Royal Dutch Shell (NYSE: RDS-A) and ConocoPhillips (NYSE: COP), have become active in coal-bed methane plays. The target: natural gas trapped within coal seams, primarily in Queensland in the northeastern part of the nation. One of the many benefits to coal-bed methane -- also known as coal-seam gas -- is that it is far greener and cleaner-burning than fossil fuels.
So while much of the world continues to be fixated on the deepwater oil discoveries offshore Brazil and Eastern Russia, for example, I urge my Foolish friends to keep your eyes glued to the stronger gas producers. Two of the names I've already mentioned are Chesapeake and Devon. I fervently believe that within the next couple of years, the world of gas will pick up significantly. On that basis, I'd recommend that you remain represented in this slow-moving -- but promising -- sector.
Both Chesapeake and Devon have received five-star ratings from Motley Fool CAPS players. Why not weigh in on your feelings about the two companies?
Thursday, February 26, 2009
Natural Gas Drilling Produces Money & Concern
By Jon Hurdle
HICKORY, Penn. (Reuters) - On a snowy hillside in rural southwest Pennsylvania, Larry Grimm drives his truck up a steep gravel track to a hilltop reservoir surrounded by orange plastic fencing and "keep out" signs.
The pond supplies water pumped from a local creek to the natural gas wells that are springing up throughout Mount Pleasant Township, where Grimm is the municipal supervisor.
Range Resources Corp, the Texas company that has drilled 68 wells in the township, needs millions of gallons of water for "hydrofracking," a process that forces a chemical-laden solution deep into the rock, allowing natural gas to be released.
The technique is being repeated at hundreds of other sites in Pennsylvania and parts of surrounding states as energy companies scramble to exploit the Marcellus Shale, one of America's biggest natural gas formations, which some geologists believe contains enough recoverable gas to meet total U.S. needs for a decade or more.
At a time when America is stepping up efforts to reduce its dependence on foreign energy, the Marcellus appears to offer an abundant alternative close to America's biggest natural gas market, the northeast.
But Grimm and others in Hickory say they have already paid a high price for the development of their quiet community from the noise of drills and compressors, heavy truck traffic damaging local roads, and air pollution from flaring or escaping gas.
They also say that Range, one of the biggest players in Marcellus drilling, appears determined to tap the vast reserve regardless of local concerns.
"They have lied to us so much," Grimm told Reuters. He said the company has exceeded the promised number of workers on its drill sites, and flared, or burned, excess gas when it said it wouldn't.
"This was almost a pristine township. They have taken the innocence off it," he said.
Grimm said he has no evidence that drilling is contaminating groundwater, but is aware of concerns that the "fracking" fluid may escape -- either above or below ground -- and that the chemicals in it have the potential to cause cancer, damage human immune and reproductive systems, and trigger other illnesses.
Ron Gulla, another township resident, blames drilling on his land for the death of vegetation and fish in his pond.
KEY WATERSHED UNDER THREAT?
According to the Endocrine Disruption Exchange, a research organization in Paonia, Colorado, 30 percent of 54 tested chemicals used in the fluid are carcinogenic; 74 percent can cause respiratory damage, and 54 percent pose a danger to the blood and cardiovascular systems.
The group tested soil and water after spills in Colorado and Wyoming where gas drilling is more advanced than in the Marcellus.
In northeastern Pennsylvania, drilling also threatens the Delaware River watershed, the source of water for 15 million people living in New York, Pennsylvania and New Jersey, according to Damascus Citizens for Sustainability, a group that opposes the development.
According to the organization, 245 chemicals including methanol, benzene, glycol ethers and biocides are used in the fluid.
Matt Pitzarella, a spokesman for Range Resources, said the fracking chemicals could be dangerous in high concentrations but are heavily diluted and so pose no threat to human health. Wells have several layers of steel and concrete to stop the fluid escaping into aquifers where they could contaminate drinking water, he said.
About 80 percent of the fracking fluid remains about a mile underground -- thousands of feet below drinking-water aquifers -- where it "dissipates" into the rock after drilling, Pitzarella said. The remainder is treated on the surface and then returned to local water sources.
Scott Anderson, a senior policy adviser with the nonprofit Environmental Defense Fund, agreed with Range's assertion that the fracking chemicals are sufficiently diluted not to pose an immediate threat to health, and he said energy companies have improved safeguards against spills.
But Anderson said he is concerned about the safe disposal of fracking concentrate that is separated from waste water after drilling, and says there is still a risk that the original fluid may be spilled before it is put in the ground. "Dilution isn't the solution to pollution," he said.
Joyce Mitchell, owner of a 133-acre (54-hectare) farm near Hickory, said she has "mixed feelings" about having leased her land to Range Resources for gas drilling. Although she has welcomed the extra income from the lease and production royalties, she complains about a constant smell of gas, and no longer drinks the water from her well because she is concerned about its safety.
Mitchell said Range took over more of her land than she expected, and though she was advised by her lawyer that the company was within its leasing rights to do so, she found the company's attitude overbearing. "They are arrogant," she said.
Now Mitchell has asked an independent testing company to make sure her water is safe. "I do feel the compulsion to make sure this operation does not do horrible things to us," she said.
(Editing by Eric Walsh)
HICKORY, Penn. (Reuters) - On a snowy hillside in rural southwest Pennsylvania, Larry Grimm drives his truck up a steep gravel track to a hilltop reservoir surrounded by orange plastic fencing and "keep out" signs.
The pond supplies water pumped from a local creek to the natural gas wells that are springing up throughout Mount Pleasant Township, where Grimm is the municipal supervisor.
Range Resources Corp, the Texas company that has drilled 68 wells in the township, needs millions of gallons of water for "hydrofracking," a process that forces a chemical-laden solution deep into the rock, allowing natural gas to be released.
The technique is being repeated at hundreds of other sites in Pennsylvania and parts of surrounding states as energy companies scramble to exploit the Marcellus Shale, one of America's biggest natural gas formations, which some geologists believe contains enough recoverable gas to meet total U.S. needs for a decade or more.
At a time when America is stepping up efforts to reduce its dependence on foreign energy, the Marcellus appears to offer an abundant alternative close to America's biggest natural gas market, the northeast.
But Grimm and others in Hickory say they have already paid a high price for the development of their quiet community from the noise of drills and compressors, heavy truck traffic damaging local roads, and air pollution from flaring or escaping gas.
They also say that Range, one of the biggest players in Marcellus drilling, appears determined to tap the vast reserve regardless of local concerns.
"They have lied to us so much," Grimm told Reuters. He said the company has exceeded the promised number of workers on its drill sites, and flared, or burned, excess gas when it said it wouldn't.
"This was almost a pristine township. They have taken the innocence off it," he said.
Grimm said he has no evidence that drilling is contaminating groundwater, but is aware of concerns that the "fracking" fluid may escape -- either above or below ground -- and that the chemicals in it have the potential to cause cancer, damage human immune and reproductive systems, and trigger other illnesses.
Ron Gulla, another township resident, blames drilling on his land for the death of vegetation and fish in his pond.
KEY WATERSHED UNDER THREAT?
According to the Endocrine Disruption Exchange, a research organization in Paonia, Colorado, 30 percent of 54 tested chemicals used in the fluid are carcinogenic; 74 percent can cause respiratory damage, and 54 percent pose a danger to the blood and cardiovascular systems.
The group tested soil and water after spills in Colorado and Wyoming where gas drilling is more advanced than in the Marcellus.
In northeastern Pennsylvania, drilling also threatens the Delaware River watershed, the source of water for 15 million people living in New York, Pennsylvania and New Jersey, according to Damascus Citizens for Sustainability, a group that opposes the development.
According to the organization, 245 chemicals including methanol, benzene, glycol ethers and biocides are used in the fluid.
Matt Pitzarella, a spokesman for Range Resources, said the fracking chemicals could be dangerous in high concentrations but are heavily diluted and so pose no threat to human health. Wells have several layers of steel and concrete to stop the fluid escaping into aquifers where they could contaminate drinking water, he said.
About 80 percent of the fracking fluid remains about a mile underground -- thousands of feet below drinking-water aquifers -- where it "dissipates" into the rock after drilling, Pitzarella said. The remainder is treated on the surface and then returned to local water sources.
Scott Anderson, a senior policy adviser with the nonprofit Environmental Defense Fund, agreed with Range's assertion that the fracking chemicals are sufficiently diluted not to pose an immediate threat to health, and he said energy companies have improved safeguards against spills.
But Anderson said he is concerned about the safe disposal of fracking concentrate that is separated from waste water after drilling, and says there is still a risk that the original fluid may be spilled before it is put in the ground. "Dilution isn't the solution to pollution," he said.
Joyce Mitchell, owner of a 133-acre (54-hectare) farm near Hickory, said she has "mixed feelings" about having leased her land to Range Resources for gas drilling. Although she has welcomed the extra income from the lease and production royalties, she complains about a constant smell of gas, and no longer drinks the water from her well because she is concerned about its safety.
Mitchell said Range took over more of her land than she expected, and though she was advised by her lawyer that the company was within its leasing rights to do so, she found the company's attitude overbearing. "They are arrogant," she said.
Now Mitchell has asked an independent testing company to make sure her water is safe. "I do feel the compulsion to make sure this operation does not do horrible things to us," she said.
(Editing by Eric Walsh)
Wednesday, February 25, 2009
States May Block Offshore Natural Gas & Oil Drilling
By H. JOSEF HEBERT – 5 hours ago
WASHINGTON (AP) — Representatives of several coastal states told a congressional hearing Tuesday that states' views must be taken into account before the federal government allows oil drilling in federal offshore waters. And some states made clear they want no drilling, period.
"There should be no ambiguity about where California stands on the issue of new offshore oil and gas leasing off California. We oppose it," said Mike Chrisman, the state's secretary for natural resources. Chrisman made the statement in testimony before the House Natural Resources Committee.
Chrisman said California Gov. Arnold Schwarzenegger and other state officials were prepared to use permitting authority coastal management programs to thwart any new drilling plans.
Ted Diers, chairman of the Coastal States Organization, which represents governors of coastal states, said any offshore energy development — oil, gas, or renewable sources such as wind or wave energy — must have states as full partners with revenues being shared with the states.
"It is vital for state authority and sovereignty to be maintained," said Diers, who manages New Hampshire's coastal programs.
The state officials appeared before the second of three hearings being held by Rep. Nick Rahall, D-W.Va., on whether a drilling moratorium should be reimposed in some areas of the Outer Continental Shelf. A long-standing moratorium over 85 percent of federal waters expired last October.
Oil and gas industry executives were to testify before the panel on Wednesday, but not before various drilling opponents had their say during a hearing earlier this month and on Tuesday when the focus was on state's concerns.
Rahall said he was not against offshore oil and gas drilling, but wants to explore during the hearings "the trade-offs that would be involved."
But the political shift on offshore energy development in the Democratic-controlled Congress was not lost as executives of the largest oil companies were left, waiting to testify last on Wednesday.
Seeking to get their views out, several oil executives and the industry's Washington lobbying group held a conference call with reporters Tuesday just as Rahall's committee began its hearing.
Marvin Odum, president of Shell Oil Co., and Larry Nichols, chairman of Devon Energy Corp., did not want to suggest they were being ignored with all the emphasis at the White House and Congress on renewable energy sources.
"I don't think it's a trade-off" between oil and gas and renewable energy, said Odum.
Nichols said the message he and the other executives want Congress to hear is that "for decades to come the vast majority of our energy is going to come from our historic sources, mainly oil and natural gas" and there are substantial resources in federal coastal waters.
Opening Tuesday's hearing, Rahall said "the coastal states are critical in this discussion."
Support for offshore energy development among the states that no do not have it ranges from tepid to staunch opposition.
Like Schwarzenegger in California, the governors of Oregon and Washington also have made clear their opposition to opening federal waters off their coasts to drilling, said Chrisman.
The Bush administration portrayed Virginia as being ready to accept oil development, but Rahall released a letter from Virginia Gov. Tim Kaine asking Interior Secretary Ken Salazar to postpone any lease sale off Virginia. While the state favors exploration for natural gas off its coast, "Our policies do not support exploration for oil or production of gas or oil," Kaine wrote in the letter dated Feb. 19.
Virginia state Sen. Frank Wagner, told the committee he personally favored "a much broader approach" that would allow oil production with a sharing of revenues with the state.
"I need not tell you states are struggling," said Wagner, suggesting oil leasing money would help.
Robert Marvinney, Maine's state geologist, acknowledged competing economic pressures when it comes to offshore development.
More than any other state, Maine is dependent on fuel oil for heating, he noted, and Georges Banks oil off New England "could provide benefits to the state of Maine." But, he said, Georges Bank also has great economic value to the region as a fishery and "we are concerned about potential negative impacts" that oil and gas development might have on the fishing industry.
WASHINGTON (AP) — Representatives of several coastal states told a congressional hearing Tuesday that states' views must be taken into account before the federal government allows oil drilling in federal offshore waters. And some states made clear they want no drilling, period.
"There should be no ambiguity about where California stands on the issue of new offshore oil and gas leasing off California. We oppose it," said Mike Chrisman, the state's secretary for natural resources. Chrisman made the statement in testimony before the House Natural Resources Committee.
Chrisman said California Gov. Arnold Schwarzenegger and other state officials were prepared to use permitting authority coastal management programs to thwart any new drilling plans.
Ted Diers, chairman of the Coastal States Organization, which represents governors of coastal states, said any offshore energy development — oil, gas, or renewable sources such as wind or wave energy — must have states as full partners with revenues being shared with the states.
"It is vital for state authority and sovereignty to be maintained," said Diers, who manages New Hampshire's coastal programs.
The state officials appeared before the second of three hearings being held by Rep. Nick Rahall, D-W.Va., on whether a drilling moratorium should be reimposed in some areas of the Outer Continental Shelf. A long-standing moratorium over 85 percent of federal waters expired last October.
Oil and gas industry executives were to testify before the panel on Wednesday, but not before various drilling opponents had their say during a hearing earlier this month and on Tuesday when the focus was on state's concerns.
Rahall said he was not against offshore oil and gas drilling, but wants to explore during the hearings "the trade-offs that would be involved."
But the political shift on offshore energy development in the Democratic-controlled Congress was not lost as executives of the largest oil companies were left, waiting to testify last on Wednesday.
Seeking to get their views out, several oil executives and the industry's Washington lobbying group held a conference call with reporters Tuesday just as Rahall's committee began its hearing.
Marvin Odum, president of Shell Oil Co., and Larry Nichols, chairman of Devon Energy Corp., did not want to suggest they were being ignored with all the emphasis at the White House and Congress on renewable energy sources.
"I don't think it's a trade-off" between oil and gas and renewable energy, said Odum.
Nichols said the message he and the other executives want Congress to hear is that "for decades to come the vast majority of our energy is going to come from our historic sources, mainly oil and natural gas" and there are substantial resources in federal coastal waters.
Opening Tuesday's hearing, Rahall said "the coastal states are critical in this discussion."
Support for offshore energy development among the states that no do not have it ranges from tepid to staunch opposition.
Like Schwarzenegger in California, the governors of Oregon and Washington also have made clear their opposition to opening federal waters off their coasts to drilling, said Chrisman.
The Bush administration portrayed Virginia as being ready to accept oil development, but Rahall released a letter from Virginia Gov. Tim Kaine asking Interior Secretary Ken Salazar to postpone any lease sale off Virginia. While the state favors exploration for natural gas off its coast, "Our policies do not support exploration for oil or production of gas or oil," Kaine wrote in the letter dated Feb. 19.
Virginia state Sen. Frank Wagner, told the committee he personally favored "a much broader approach" that would allow oil production with a sharing of revenues with the state.
"I need not tell you states are struggling," said Wagner, suggesting oil leasing money would help.
Robert Marvinney, Maine's state geologist, acknowledged competing economic pressures when it comes to offshore development.
More than any other state, Maine is dependent on fuel oil for heating, he noted, and Georges Banks oil off New England "could provide benefits to the state of Maine." But, he said, Georges Bank also has great economic value to the region as a fishery and "we are concerned about potential negative impacts" that oil and gas development might have on the fishing industry.
Tuesday, February 24, 2009
Venoco Buys Natural Gas Wells in California
San Francisco Business Times
Venoco (NYSE: VQ) owns interests in about 111 wells in the Sacramento natural gas basin. It also owns offshore and onshore oil rigs and wells in Southern California and Texas.
Venoco's local holdings include the Sacramento Delta Fields in Solano County, bought from Chevron in 1998, fields in Contra Costa County, and fields in Sacramento and in San Joaquin County, according to the company's Web site.
Aspen (OTCBB: ASPN) operated 55 natural gas wells in California's Sacramento Valley and owns interests in another 20 wells. The company also has oil and gas interests in Montana, which are not part of the deal.
A group of people and businesses who own working interests in the wells, including three Aspen directors and a broker that helped arrange the deal with Venoco, will have the opportunity to sell their interests, according to a statement from Aspen. The total purchase price could reach $25 million if they all participate.
The deal requires approval of Aspen shareholders at a meeting the company plans to hold in April or later.
Venoco said in a statement Friday that its proven oil and natural gas reserves at the end of last year were equivalent of 97.5 million barrels of oil, worth about $616.7 million at the end of the year. The value is an estimate of future revenue before income taxes, discounted 10 percent, which is a standard measurement of asset value in the oil and gas industry.
Venoco’s oil and natural gas production was the equivalent of 7.9 million barrels last year, or 21,674 barrels per day. That was an 11 percent increase from 2007. The company expects to produce the equivalent of 19,000 barrels of oil per day this year.
Production from the Sacramento region climbed in the fourth quarter, but the company plans to run three drilling rigs in the basin this year, down from five last year.
Venoco plans to spend about $74 million on developing wells and other capital expenditures in the Sacramento basin this year.
Venoco (NYSE: VQ) owns interests in about 111 wells in the Sacramento natural gas basin. It also owns offshore and onshore oil rigs and wells in Southern California and Texas.
Venoco's local holdings include the Sacramento Delta Fields in Solano County, bought from Chevron in 1998, fields in Contra Costa County, and fields in Sacramento and in San Joaquin County, according to the company's Web site.
Aspen (OTCBB: ASPN) operated 55 natural gas wells in California's Sacramento Valley and owns interests in another 20 wells. The company also has oil and gas interests in Montana, which are not part of the deal.
A group of people and businesses who own working interests in the wells, including three Aspen directors and a broker that helped arrange the deal with Venoco, will have the opportunity to sell their interests, according to a statement from Aspen. The total purchase price could reach $25 million if they all participate.
The deal requires approval of Aspen shareholders at a meeting the company plans to hold in April or later.
Venoco said in a statement Friday that its proven oil and natural gas reserves at the end of last year were equivalent of 97.5 million barrels of oil, worth about $616.7 million at the end of the year. The value is an estimate of future revenue before income taxes, discounted 10 percent, which is a standard measurement of asset value in the oil and gas industry.
Venoco’s oil and natural gas production was the equivalent of 7.9 million barrels last year, or 21,674 barrels per day. That was an 11 percent increase from 2007. The company expects to produce the equivalent of 19,000 barrels of oil per day this year.
Production from the Sacramento region climbed in the fourth quarter, but the company plans to run three drilling rigs in the basin this year, down from five last year.
Venoco plans to spend about $74 million on developing wells and other capital expenditures in the Sacramento basin this year.
Monday, February 23, 2009
Natural Gas Important to USA
Domestic natural gas one hope
By Adam Testa, The Southern
Sunday, February 22, 2009 2:14 AM CST
In the debate on preferred energy sources for America to pursue, most experts will agree that natural gas offers one of the most environmentally clean options.
Supply, however, has become an issue of concern as America's energy usage continues to grow, and North America maintains only 4 percent of the world's known natural gas supply. A majority of the supply lies in the Middle East and eastern European countries.
While natural gas primarily comes from the same geographic regions as oil, America has managed to avoid the complications and threats associated with importation. The United States self-produces 85 percent of its natural gas consumption.
As usage continues to expand, some believe importing will become a necessary path, but others believe new technologies can help keep America's gas supply originating at home.
Scott Williams, a West Frankfort-based consultant in the natural gas industry, has worked with Michigan-based DTE Methane Resources to extract methane gas from sealed coal mines in Franklin, Jefferson and Williamson counties.
Once extracted from the closed-off mines, the gas is transported to a DTE plant near Corinth where it is cleaned and converted so it can be sold on the market or shipped off through pipelines. This coal bed methane production represents the most prominent form of natural gas manufacturing in Illinois.
"Some of the mines have no gas in them; some of them are flooded," Williams said. "The gas in some of them is such low quality it's not worth trying to produce."
The high cost of infrastructure necessary to test and drill for viable mining locations makes the venture cost-prohibitive for energy companies unless natural gas prices stay about a certain price level, Williams said.
New technologies will allow for further development and expansion of the natural gas market in the United States and Illinois, he added. Among possibilities being explored are coal gasification and drilling for gas in virgin coal reserves.
Brad Richards, executive vice president of the Illinois Oil and Gas Association, said researchers have also begun to apply the practice of extracting gases from shale, which was previously thought to be too tight of a rock to be mined.
The type shale best suited for natural gas extraction can be found in Arkansas, Louisiana, Pennsylvania and Texas, Richards said. In its early stages, several hurdles still stand in the path of shale extraction, but Richards believes it will play a major role as America moves forward.
"There are issues there that will have to be resolved, but the natural gas is definitely there," he said.
adam.testa@thesouthern.com / 618-351-5031
By Adam Testa, The Southern
Sunday, February 22, 2009 2:14 AM CST
In the debate on preferred energy sources for America to pursue, most experts will agree that natural gas offers one of the most environmentally clean options.
Supply, however, has become an issue of concern as America's energy usage continues to grow, and North America maintains only 4 percent of the world's known natural gas supply. A majority of the supply lies in the Middle East and eastern European countries.
While natural gas primarily comes from the same geographic regions as oil, America has managed to avoid the complications and threats associated with importation. The United States self-produces 85 percent of its natural gas consumption.
As usage continues to expand, some believe importing will become a necessary path, but others believe new technologies can help keep America's gas supply originating at home.
Scott Williams, a West Frankfort-based consultant in the natural gas industry, has worked with Michigan-based DTE Methane Resources to extract methane gas from sealed coal mines in Franklin, Jefferson and Williamson counties.
Once extracted from the closed-off mines, the gas is transported to a DTE plant near Corinth where it is cleaned and converted so it can be sold on the market or shipped off through pipelines. This coal bed methane production represents the most prominent form of natural gas manufacturing in Illinois.
"Some of the mines have no gas in them; some of them are flooded," Williams said. "The gas in some of them is such low quality it's not worth trying to produce."
The high cost of infrastructure necessary to test and drill for viable mining locations makes the venture cost-prohibitive for energy companies unless natural gas prices stay about a certain price level, Williams said.
New technologies will allow for further development and expansion of the natural gas market in the United States and Illinois, he added. Among possibilities being explored are coal gasification and drilling for gas in virgin coal reserves.
Brad Richards, executive vice president of the Illinois Oil and Gas Association, said researchers have also begun to apply the practice of extracting gases from shale, which was previously thought to be too tight of a rock to be mined.
The type shale best suited for natural gas extraction can be found in Arkansas, Louisiana, Pennsylvania and Texas, Richards said. In its early stages, several hurdles still stand in the path of shale extraction, but Richards believes it will play a major role as America moves forward.
"There are issues there that will have to be resolved, but the natural gas is definitely there," he said.
adam.testa@thesouthern.com / 618-351-5031
Sunday, February 22, 2009
European Companies Eye U.S. Natural Gas
American drilling techniques may migrate overseas
By MARK WILLIAMS – 5 hours ago
COLUMBUS, Ohio (AP) — With one eye cast toward home, giant European energy companies are investing billions in U.S. natural gas and oil fields where huge, hard-to-get reserves have been unlocked with new drilling technology.
That technology is the prize in Europe, where gas production has declined and where an international utility dispute recently left people in more than a dozen European countries shivering in unheated homes.
Europe's natural gas supply is routed through Ukraine from Russia. Russia supplies about one-quarter of the EU's natural gas, with 80 percent of it shipped through Ukraine. A rift between the two nations left more than a dozen European countries with little or no gas for two weeks last month.
Declines in European gas production has potentially made the new techniques used in the U.S. even more pivotal.
At least three European oil and gas giants are developing or have bought interests in oil and gas shale projects in the U.S. — Norwegian oil company StatoilHydro, the U.S. unit of British oil company BP Plc and French company Total.
StatoilHydro and BP have agreed in recent months to pay billions of dollars for stakes in shale gas projects from the top U.S. producer of gas, Chesapeake Energy. Total has bought a 50 percent stake in a U.S. company exploring for oil shale in the Rocky Mountains.
"Given the magnitude of oil shale resources we believe that this project has an important long-term potential for global energy markets," Yves-Louis Darricarrere, Total's exploration and production president, said in announcing Total's deal with American Shale Oil.
Shale is a kind of layered, sedimentary rock that exists in formations throughout the world. In the U.S., gas production from shale dates back to the 1800s.
But the gas, tightly locked in rock formations, had been extraordinarily expensive to extract. That began to change about 15 years ago as producers developed new techniques such as horizontal drilling, where the drill is turned in a right angle to bore into a gas reservoir horizontally.
Gas from shale now amounts to about 5 percent of total U.S. production, according to the Gas Technology Institute.
If the same technology works in Europe it could free up an enormous amount of energy, and potentially provide a buffer against cross-border disputes to the east.
StatoilHydro bought into Chesapeake Energy's massive Appalachian Marcellus shale project for $3.37 billion in November. Executive Vice President Rune Bjornson said at an energy conference this month in Houston that StatoilHydro wants to bring new drilling technology to other regions of the world.
If the race to duplicate drilling success in the U.S. is on, few companies are talking about it.
Even Aubrey McClendon, co-founder and chief executive of Chesapeake, the largest natural gas producer in the U.S., said, "I doubt we will trumpet it as I think the combination of their international stature and presence and our knowledge of gas shale would do nothing but attract competition."
But it has become abundantly clear since a chilly two weeks in January that Europe's energy security has been diminished since the break up of the Soviet Union.
Buying into the technology in the U.S. makes sense and could spare European companies years of development, said Don Hertzmark, an international energy expert.
"The Europeans never bothered to develop this stuff," he said.
U.S. companies stand to expand through new markets in Europe if the new techniques work, and many experts believe that they will.
Energy companies are now funding a six-year study to locate gas deposits in Europe and to determine if they can be exploited.
"The companies that are involved here — they're not beginners," said Brian Horsfield of the GFZ German Research Center, which is heading the study. "It could come online within three years if it turns out these gas shales really are as prolific as we're led to believe."
Horsfield, a professor of organic geochemistry, said companies already have acquired land rights throughout Europe.
"The shale gas, if it were to be economic here, is very close to the user," Horsfield said. "That's one of the selling points, certainly, of our project on a nonscientific basis. And the events of the last month or so have helped to stress that."
European Commission President Jose Manuel Barroso said after the dispute between Russia and Ukraine was settled (the second dispute in recent years) that Europe must diversify its energy sources and supply route.
"It was utterly unacceptable that European gas consumers were held hostage to this dispute between Russia and Ukraine," he said.
Associated Press writers Patrick McGroarty in Berlin and Greg Keller in Paris contributed to this story.
By MARK WILLIAMS – 5 hours ago
COLUMBUS, Ohio (AP) — With one eye cast toward home, giant European energy companies are investing billions in U.S. natural gas and oil fields where huge, hard-to-get reserves have been unlocked with new drilling technology.
That technology is the prize in Europe, where gas production has declined and where an international utility dispute recently left people in more than a dozen European countries shivering in unheated homes.
Europe's natural gas supply is routed through Ukraine from Russia. Russia supplies about one-quarter of the EU's natural gas, with 80 percent of it shipped through Ukraine. A rift between the two nations left more than a dozen European countries with little or no gas for two weeks last month.
Declines in European gas production has potentially made the new techniques used in the U.S. even more pivotal.
At least three European oil and gas giants are developing or have bought interests in oil and gas shale projects in the U.S. — Norwegian oil company StatoilHydro, the U.S. unit of British oil company BP Plc and French company Total.
StatoilHydro and BP have agreed in recent months to pay billions of dollars for stakes in shale gas projects from the top U.S. producer of gas, Chesapeake Energy. Total has bought a 50 percent stake in a U.S. company exploring for oil shale in the Rocky Mountains.
"Given the magnitude of oil shale resources we believe that this project has an important long-term potential for global energy markets," Yves-Louis Darricarrere, Total's exploration and production president, said in announcing Total's deal with American Shale Oil.
Shale is a kind of layered, sedimentary rock that exists in formations throughout the world. In the U.S., gas production from shale dates back to the 1800s.
But the gas, tightly locked in rock formations, had been extraordinarily expensive to extract. That began to change about 15 years ago as producers developed new techniques such as horizontal drilling, where the drill is turned in a right angle to bore into a gas reservoir horizontally.
Gas from shale now amounts to about 5 percent of total U.S. production, according to the Gas Technology Institute.
If the same technology works in Europe it could free up an enormous amount of energy, and potentially provide a buffer against cross-border disputes to the east.
StatoilHydro bought into Chesapeake Energy's massive Appalachian Marcellus shale project for $3.37 billion in November. Executive Vice President Rune Bjornson said at an energy conference this month in Houston that StatoilHydro wants to bring new drilling technology to other regions of the world.
If the race to duplicate drilling success in the U.S. is on, few companies are talking about it.
Even Aubrey McClendon, co-founder and chief executive of Chesapeake, the largest natural gas producer in the U.S., said, "I doubt we will trumpet it as I think the combination of their international stature and presence and our knowledge of gas shale would do nothing but attract competition."
But it has become abundantly clear since a chilly two weeks in January that Europe's energy security has been diminished since the break up of the Soviet Union.
Buying into the technology in the U.S. makes sense and could spare European companies years of development, said Don Hertzmark, an international energy expert.
"The Europeans never bothered to develop this stuff," he said.
U.S. companies stand to expand through new markets in Europe if the new techniques work, and many experts believe that they will.
Energy companies are now funding a six-year study to locate gas deposits in Europe and to determine if they can be exploited.
"The companies that are involved here — they're not beginners," said Brian Horsfield of the GFZ German Research Center, which is heading the study. "It could come online within three years if it turns out these gas shales really are as prolific as we're led to believe."
Horsfield, a professor of organic geochemistry, said companies already have acquired land rights throughout Europe.
"The shale gas, if it were to be economic here, is very close to the user," Horsfield said. "That's one of the selling points, certainly, of our project on a nonscientific basis. And the events of the last month or so have helped to stress that."
European Commission President Jose Manuel Barroso said after the dispute between Russia and Ukraine was settled (the second dispute in recent years) that Europe must diversify its energy sources and supply route.
"It was utterly unacceptable that European gas consumers were held hostage to this dispute between Russia and Ukraine," he said.
Associated Press writers Patrick McGroarty in Berlin and Greg Keller in Paris contributed to this story.
Saturday, February 21, 2009
Natural Gas Prices Continue to Fall in Kentucky
Feb. 20--Kentucky residents will see lower natural gas costs in February than they did at the start of the heating season in November, according to the Kentucky Public Service Commission. The latest round of natural gas cost adjustments approved for Kentucky's five largest natural gas distribution utilities show an average decline of $1.10 per 1,000 cubic feet of gas. A typical customer using 10,000 cubic feet of gas per month will pay $11 less for gas than three months ago. One of the five largest, Atmos Energy, isn't seeing such a large decrease, but is still trying to average out gas prices from the summer. "We're still roughly at $11 per cubic foot," said Kay Comes, with Atmos. "Last year, gas prices were really high and we were trying to average them out and we're still trying to keep that recovered through the winter. Hopefully by spring we'll see those prices come down for our customers, but anything can change. It's a daily process and we're keeping our fingers crossed." Atmos Energy supplies natural gas for 12 states including Kentucky. The Atmos Kentucky/Mid-States division covers Barren and Hart among other counties. These declines show that the downturn in the wholesale price of natural gas is making its way to customers," said PSC chairman David Armstrong in a news release. "If wholesale prices remain low, consumers should see further decreases in their costs in the coming months." In November, customers of Kentucky's five largest distribution companies were paying an average of $11.70 per cubic foot of gas. In January, the average was $10.60 per cubic foot. In February the average cost is $9.63. Based on filings received from companies that will readjust their gas costs in March, the average cost per cubic foot will decline again next month. Natural gas prices peaked last summer, according to a news release. Because wholesale costs must be passed on to consumers on a dollar-to-dollar basis, retail prices this winter are reflecting the cost of that stored gas as it is withdrawn and used. As the stored gas is consumed and replaced by or mixed with lower-priced gas bought more recently, the cost to consumers should continue to decline, according to the release. The five largest distribution companies in Kentucky are Atmos Energy, Columbia Gas of Kentucky Inc., Delta Natural Gas Inc., Louisville Gas and Electric Co. and Duke Energy Kentucky, Inc. Together the five companies serve more than 750,000 customers in Kentucky and deliver about 176 billion cubic feet of gas annually. Approximately 44 percent of Kentuckians heat their homes with natural gas.
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To see more of the Glasgow Daily Times or to subscribe to the newspaper, go to http://www.glasgowdailytimes.com/.
Copyright (c) 2009, Glasgow Daily Times, Ky.
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To see more of the Glasgow Daily Times or to subscribe to the newspaper, go to http://www.glasgowdailytimes.com/.
Copyright (c) 2009, Glasgow Daily Times, Ky.
Friday, February 20, 2009
Russian Natural Gas to Asia
By ANDREW E. KRAMER
Published: February 18, 2009 - New York Times
MOSCOW — Russia has profited handsomely from natural gas exports to Europe. Now, after years of false starts and disputes, and mutual suspicions between Moscow and Beijing, Russia is turning its attention to Asia.
The moves are prompted by both the promise of a marriage of Russian resources with Asian manufacturing, and Russia’s financial desperation as interest from Western banks and investors dries up.
On Wednesday — just a day after agreeing to supply oil to China for the next 20 years, in exchange for $25 billion in loan guarantees — Russia opened its first liquefied natural gas plant to supply fuel to Asia.
The plant, built on Sakhalin Island north of Japan and part of the $22 billion Sakhalin 2 development, will greatly expand Russia’s natural gas empire. In fact, futures contracts have already been signed to ship Russian gas as far away as the West Coast of the United States.
The Russians are hoping Asian governments, with their enormous cash reserves, can compensate for the vast sums Western investors have pulled out of Russia in recent months. China, meanwhile, sees an opportunity to invest cheaply in natural resources it will need when its economy recovers.
Sakhalin 2 is the largest Russian energy project supplying Asia to come into production to date.
Though partly nationalized by the state energy company Gazprom in 2006, it is still operated by its original developer, the British-Dutch oil giant Royal Dutch Shell. Two Japanese trading houses, Mitsui and Mitsubishi, are also partners.
The development links three offshore platforms, hundreds of miles of pipelines and the liquefied natural gas plant along an isolated stretch of Pacific coastline. When it reaches full capacity in 2010, it will chill and ship about 5 percent of the world’s liquefied natural gas supply.
President Dmitri A. Medvedev of Russia and Prime Minister Taro Aso of Japan attended the opening Wednesday.
Apparently addressing worries in Europe over Russia’s use of energy as a political weapon, Mr. Medvedev struck a conciliatory tone, acknowledging that “mistakes” were made in Russian energy policy in the past.
“At times we do not fully calculate political risks and practical consequences,” Mr. Medvedev said, without elaborating, according to the Itar-Tass news service.
Still, Russia’s energy ambitions in the Asian Pacific are only gathering momentum.
This week, Russia’s national oil company, Rosneft, and national pipeline operator, Transneft, completed a deal for $25 billion in loans from the China Development Bank. In exchange, the Russian companies agreed to provide 300,000 barrels of oil a day to China over 20 years through a trans-Siberian oil pipeline that is scheduled to reach China in 2010.
Russia’s economic situation has so deteriorated that even typically upbeat financial analysts have been taking on a funereal tone.
Chris Weafer, chief analyst for UralSib bank in Moscow, published a research note Wednesday describing the Russian equity markets as “a highway along which asset valuations and investor sentiments are being driven by the infernal troika of oil, ruble and economy. All three of which have reached the banks of the river Styx and are scrambling to find the appropriate number of kopeks to pay the ferryman.”
In a measure of Russia’s economic troubles, corporations here must repay $117 billion in debt to Western banks this year, in a stark reversal from the inflow of foreign investor money that buoyed Russia’s economy in recent years.
Thus, the $25 billion oil deal with China will offset nearly a quarter of this so-called capital account deficit in 2009. This deficit is one factor pushing down the ruble’s value and depressing the Moscow stock exchanges.
If the global recession deepens, the Kremlin may be willing to put more on sale, economists say.
“If the situation remains tense in Russia and the world economy, we will see more concessions to China,” possibly in metals or mining as well as energy, Vladimir I. Tikhomirov, chief economist at UralSib, said in a telephone interview.
The Sakhalin 2 site, in the works since the early 1990s, has had a turbulent history. In 2006, a Russian environmental regulator threatened to halt work on a pipeline, claiming illegal logging and damage to salmon streams.
After a tense few months, Shell and the Japanese trading houses agreed to sell 50 percent plus one share — a controlling stake — to Gazprom for $7.45 billion. After the sale, the environmental objections were lifted.
Published: February 18, 2009 - New York Times
MOSCOW — Russia has profited handsomely from natural gas exports to Europe. Now, after years of false starts and disputes, and mutual suspicions between Moscow and Beijing, Russia is turning its attention to Asia.
The moves are prompted by both the promise of a marriage of Russian resources with Asian manufacturing, and Russia’s financial desperation as interest from Western banks and investors dries up.
On Wednesday — just a day after agreeing to supply oil to China for the next 20 years, in exchange for $25 billion in loan guarantees — Russia opened its first liquefied natural gas plant to supply fuel to Asia.
The plant, built on Sakhalin Island north of Japan and part of the $22 billion Sakhalin 2 development, will greatly expand Russia’s natural gas empire. In fact, futures contracts have already been signed to ship Russian gas as far away as the West Coast of the United States.
The Russians are hoping Asian governments, with their enormous cash reserves, can compensate for the vast sums Western investors have pulled out of Russia in recent months. China, meanwhile, sees an opportunity to invest cheaply in natural resources it will need when its economy recovers.
Sakhalin 2 is the largest Russian energy project supplying Asia to come into production to date.
Though partly nationalized by the state energy company Gazprom in 2006, it is still operated by its original developer, the British-Dutch oil giant Royal Dutch Shell. Two Japanese trading houses, Mitsui and Mitsubishi, are also partners.
The development links three offshore platforms, hundreds of miles of pipelines and the liquefied natural gas plant along an isolated stretch of Pacific coastline. When it reaches full capacity in 2010, it will chill and ship about 5 percent of the world’s liquefied natural gas supply.
President Dmitri A. Medvedev of Russia and Prime Minister Taro Aso of Japan attended the opening Wednesday.
Apparently addressing worries in Europe over Russia’s use of energy as a political weapon, Mr. Medvedev struck a conciliatory tone, acknowledging that “mistakes” were made in Russian energy policy in the past.
“At times we do not fully calculate political risks and practical consequences,” Mr. Medvedev said, without elaborating, according to the Itar-Tass news service.
Still, Russia’s energy ambitions in the Asian Pacific are only gathering momentum.
This week, Russia’s national oil company, Rosneft, and national pipeline operator, Transneft, completed a deal for $25 billion in loans from the China Development Bank. In exchange, the Russian companies agreed to provide 300,000 barrels of oil a day to China over 20 years through a trans-Siberian oil pipeline that is scheduled to reach China in 2010.
Russia’s economic situation has so deteriorated that even typically upbeat financial analysts have been taking on a funereal tone.
Chris Weafer, chief analyst for UralSib bank in Moscow, published a research note Wednesday describing the Russian equity markets as “a highway along which asset valuations and investor sentiments are being driven by the infernal troika of oil, ruble and economy. All three of which have reached the banks of the river Styx and are scrambling to find the appropriate number of kopeks to pay the ferryman.”
In a measure of Russia’s economic troubles, corporations here must repay $117 billion in debt to Western banks this year, in a stark reversal from the inflow of foreign investor money that buoyed Russia’s economy in recent years.
Thus, the $25 billion oil deal with China will offset nearly a quarter of this so-called capital account deficit in 2009. This deficit is one factor pushing down the ruble’s value and depressing the Moscow stock exchanges.
If the global recession deepens, the Kremlin may be willing to put more on sale, economists say.
“If the situation remains tense in Russia and the world economy, we will see more concessions to China,” possibly in metals or mining as well as energy, Vladimir I. Tikhomirov, chief economist at UralSib, said in a telephone interview.
The Sakhalin 2 site, in the works since the early 1990s, has had a turbulent history. In 2006, a Russian environmental regulator threatened to halt work on a pipeline, claiming illegal logging and damage to salmon streams.
After a tense few months, Shell and the Japanese trading houses agreed to sell 50 percent plus one share — a controlling stake — to Gazprom for $7.45 billion. After the sale, the environmental objections were lifted.
Thursday, February 19, 2009
Bradford Natural Gas Terminal Receives Court Challenge
2/18/2009, 2:29 p.m. PST
The Associated Press
ASTORIA, Ore. (AP) — After asking a federal appeals court to block a liquefied natural gas terminal on the Columbia River, Oregon Attorney General John Kroger has asked federal regulators to wait for a ruling.
Kroger filed a request with the Federal Energy Regulatory Commission last Friday asking the commission to stay its September approval of the Bradwood Landing project until the 9th U.S. Circuit Court of Appeals rules on the state's challenge.
Kroger also asked the commission to wait until Oregon issues the state permits needed to build the LNG facility.The stay, if granted by FERC, would prevent the Office of Energy Projects from approving any final designs or construction plans that do not comply with state laws.
Oregon first challenged federal regulatory approval in October, arguing the commission had jumped the gun in issuing an order approving the project before state approvals and federal environmental reviews were complete.
In January, FERC denied Oregon's request for a rehearing of the Bradwood case.
Kroger then took the state challenge to the 9th Circuit, arguing the commission's environmental analysis was flawed and that it acted prematurely.
The Bradwood project is being developed by NorthernStar Natural Gas Inc. of Houston, which had hoped to begin construction in 2007. Company officials have said they will continue working on state permits during the appeal.
In related action, Columbia Riverkeeper and partners filed a challenge in federal court last Thursday, seeking to overturn FERC's approval of the Bradwood terminal.
Also on Thursday, the Washington state Department of Ecology said it would file a federal court challenge.
"We are pleased that the states of Oregon and Washington have joined this challenge," said Columbia Riverkeeper Executive Director Brett VandenHeuvel.
"The broad coalition opposing FERC's approval is an indictment of the Bush administration's flawed decision and flawed energy policy," VandenHeuvel said.
The Associated Press
ASTORIA, Ore. (AP) — After asking a federal appeals court to block a liquefied natural gas terminal on the Columbia River, Oregon Attorney General John Kroger has asked federal regulators to wait for a ruling.
Kroger filed a request with the Federal Energy Regulatory Commission last Friday asking the commission to stay its September approval of the Bradwood Landing project until the 9th U.S. Circuit Court of Appeals rules on the state's challenge.
Kroger also asked the commission to wait until Oregon issues the state permits needed to build the LNG facility.The stay, if granted by FERC, would prevent the Office of Energy Projects from approving any final designs or construction plans that do not comply with state laws.
Oregon first challenged federal regulatory approval in October, arguing the commission had jumped the gun in issuing an order approving the project before state approvals and federal environmental reviews were complete.
In January, FERC denied Oregon's request for a rehearing of the Bradwood case.
Kroger then took the state challenge to the 9th Circuit, arguing the commission's environmental analysis was flawed and that it acted prematurely.
The Bradwood project is being developed by NorthernStar Natural Gas Inc. of Houston, which had hoped to begin construction in 2007. Company officials have said they will continue working on state permits during the appeal.
In related action, Columbia Riverkeeper and partners filed a challenge in federal court last Thursday, seeking to overturn FERC's approval of the Bradwood terminal.
Also on Thursday, the Washington state Department of Ecology said it would file a federal court challenge.
"We are pleased that the states of Oregon and Washington have joined this challenge," said Columbia Riverkeeper Executive Director Brett VandenHeuvel.
"The broad coalition opposing FERC's approval is an indictment of the Bush administration's flawed decision and flawed energy policy," VandenHeuvel said.
Wednesday, February 18, 2009
Petroplus Delays Oil Refining Project
By Grant Smith
Feb. 17 (Bloomberg) -- Petroplus Holdings AG, Europe’s largest independent oil refiner by capacity, said that refining projects amounting to at least 1.5 million barrels a day will be either delayed or cancelled this year.
The hold-ups affect seven projects by various oil companies spread across the Middle East, Asia and the U.S., according to a presentation by Zug, Switzerland-based Petroplus, published on its Web site today.
The largest of the affected projects is the expansion of Saudi Aramco and Royal Dutch Shell Plc’s Jubail refinery in Saudi Arabia, according to the presentation, which cited data from Wood Mackenzie Consultants Ltd. and Hart Energy.
The other refinery delays mentioned were the Fujairah project in the United Arab Emirates, Essar Oil Ltd.’s refinery in India, Ceyhan in Turkey, refinery expansions at Cilacap and Balikpapan in Indonesia and a Marathon Oil Corp. upgrading project in Detroit.
Petroplus operates eight refineries in Europe with a combined capacity of 864,000 barrels a day. Forty-seven percent of the products produced by those plants are so-called middle distillates, which include diesel and heating oil. That’s the largest category of all the oil products that Petroplus makes, followed by gasoline, which accounts for 22 percent of its production.
During the first nine months of 2008, Petroplus was the third-largest producer of middle distillates among independent oil refiners, after Valero Energy Corp. and Sunoco Inc., the report showed.
To contact the reporter on this story: Grant Smith in London at gsmith52@bloomberg.net
Last Updated: February 17, 2009 13:00 EST
Feb. 17 (Bloomberg) -- Petroplus Holdings AG, Europe’s largest independent oil refiner by capacity, said that refining projects amounting to at least 1.5 million barrels a day will be either delayed or cancelled this year.
The hold-ups affect seven projects by various oil companies spread across the Middle East, Asia and the U.S., according to a presentation by Zug, Switzerland-based Petroplus, published on its Web site today.
The largest of the affected projects is the expansion of Saudi Aramco and Royal Dutch Shell Plc’s Jubail refinery in Saudi Arabia, according to the presentation, which cited data from Wood Mackenzie Consultants Ltd. and Hart Energy.
The other refinery delays mentioned were the Fujairah project in the United Arab Emirates, Essar Oil Ltd.’s refinery in India, Ceyhan in Turkey, refinery expansions at Cilacap and Balikpapan in Indonesia and a Marathon Oil Corp. upgrading project in Detroit.
Petroplus operates eight refineries in Europe with a combined capacity of 864,000 barrels a day. Forty-seven percent of the products produced by those plants are so-called middle distillates, which include diesel and heating oil. That’s the largest category of all the oil products that Petroplus makes, followed by gasoline, which accounts for 22 percent of its production.
During the first nine months of 2008, Petroplus was the third-largest producer of middle distillates among independent oil refiners, after Valero Energy Corp. and Sunoco Inc., the report showed.
To contact the reporter on this story: Grant Smith in London at gsmith52@bloomberg.net
Last Updated: February 17, 2009 13:00 EST
Minority Owner Natural Gas Giveaway
By Toby Shute
www.fool.com
February 17, 2009 | Comments (1)
Last week, Parallel Petroleum (Nasdaq: PLLL) did just that, in agreeing to transfer half of its 35% interest in a Texas natural gas field to Chesapeake Energy (NYSE: CHK).
Chesapeake owns the majority interest in the field and calls the shots when it comes to the drilling decisions. Parallel participates by footing its proper share of the costs.
In other words, the small company doesn't control its own destiny with regards to the timing of capital spending, at least in this particular play. In today's environment, that's a tenuous situation. Parallel has thus chosen to dilute its interest in the field to get out from under a potentially crippling cash outlay in the upcoming year.
For this to be called a fire sale, I think there would have to be some number on the price tag. This is more like a game of duck, duck drill costs.
We've already seen drilling commitments sink one offshore explorer. In that case, the company was on the hook with contractors Transocean (NYSE: RIG) and Diamond Offshore (NYSE: DO). This latest move by Parallel shows that onshore players are overstretched as well.
So how can you verify that the exploration and production company you've invested in controls its own destiny? One key element is the amount of leasehold that's held by production (HBP). This status gives the company lots of leeway on the timing of its drilling program, without "use it or lose it"-type concerns.
Occidental Petroleum (NYSE: OXY), for example, has 5 million acres of leasehold in the U.S., with 70% of that HBP and another 10% on long-term leases with many years to run. Newfield Exploration (NYSE: NFX), a smaller shop, has 90% of its Woodford shale acreage HBP. The company rightfully described this as "a huge advantage in today's market" on a recent conference call.
As with Parallel, you also have to look at the company's commitments to third parties. The annual report on Form 10-K is a good place to start, but you also need to look at the major changes succeeding that handy document's publication
www.fool.com
February 17, 2009 | Comments (1)
Last week, Parallel Petroleum (Nasdaq: PLLL) did just that, in agreeing to transfer half of its 35% interest in a Texas natural gas field to Chesapeake Energy (NYSE: CHK).
Chesapeake owns the majority interest in the field and calls the shots when it comes to the drilling decisions. Parallel participates by footing its proper share of the costs.
In other words, the small company doesn't control its own destiny with regards to the timing of capital spending, at least in this particular play. In today's environment, that's a tenuous situation. Parallel has thus chosen to dilute its interest in the field to get out from under a potentially crippling cash outlay in the upcoming year.
For this to be called a fire sale, I think there would have to be some number on the price tag. This is more like a game of duck, duck drill costs.
We've already seen drilling commitments sink one offshore explorer. In that case, the company was on the hook with contractors Transocean (NYSE: RIG) and Diamond Offshore (NYSE: DO). This latest move by Parallel shows that onshore players are overstretched as well.
So how can you verify that the exploration and production company you've invested in controls its own destiny? One key element is the amount of leasehold that's held by production (HBP). This status gives the company lots of leeway on the timing of its drilling program, without "use it or lose it"-type concerns.
Occidental Petroleum (NYSE: OXY), for example, has 5 million acres of leasehold in the U.S., with 70% of that HBP and another 10% on long-term leases with many years to run. Newfield Exploration (NYSE: NFX), a smaller shop, has 90% of its Woodford shale acreage HBP. The company rightfully described this as "a huge advantage in today's market" on a recent conference call.
As with Parallel, you also have to look at the company's commitments to third parties. The annual report on Form 10-K is a good place to start, but you also need to look at the major changes succeeding that handy document's publication
Tuesday, February 17, 2009
Encana Natural Gas to Nova Scotia
HALIFAX, N.S. — EnCana (TSX:ECA) has agreed to sell the natural gas it will produce at its Deep Panuke wells off Nova Scotia to Repsol YPF SA - a Spanish oil-and-gas firm that aims to become a major supplier to the northeastern United States.
EnCana spokeswoman Lori MacLean says that the Calgary-based company's contract with Repsol takes effect immediately and will apply for the life of the offshore project, which is slated to begin in late 2010.
The project is proposing to produce 200 million cubic feet of gas per day at startup and will ramp up to 300 million cubic feet daily, roughly enough gas to heat 1,500 homes for one year.
Kristian Rix, a Barcelona-based spokesman for Repsol, said Monday in an interview that his firm believes Canada and the U.S. northeast is a lucrative market, and the company retains a goal of capturing about 20 per cent of sales in the region.
"Here's a chance to get access to more gas, and it allows us to gain market share and grow faster than we'd originally thought we'd be able to," Rix said.
No details of the deal were released.
The gas from near Sable Island, off Nova Scotia's east coast, will be available to ship through the Maritimes and Northeast pipeline to the U.S. and Canadian markets.
Steve Rankin, a spokesman for Maritimes and Northeast, said there's no firm contract in place yet with Repsol to ship over the Canadian portion of the pipeline, but he speculated the owners of the Deep Panuke gas may buy space from other companies that currently use the pipeline.
Meanwhile, Rix said, Repsol is making its first delivery of liquified natural gas by this May to the Canaport terminal near Saint John, N.B.
The joint project between Repsol and New Brunswick-based Irving Oil Ltd. will source its liquefied natural gas from Trinidad and Tobago, among other places, and ship the gas to the terminal through the company's fleet of 11 tankers.
LNG is created by cooling natural gas into a liquid state, making it easier to store and transport to overseas markets via special tankers.
The Canaport project will receive shipments of LNG, convert the liquid back into a gas, and feed it by the underground Brunswick pipeline (TSX:EMA) to the Maritimes and Northeast pipeline in the United States.
Repsol, which holds a 75 per cent stake in the Canaport LNG project, expects the terminal will be able to process one billion cubic feet per day of gas.
The Deep Panuke gas will now serve to fill any gaps in production from the Saint John facilities, he added.
There has been speculation that EnCana might eventually be interested in selling the Deep Panuke field.
Rix said that Repsol isn't commenting on whether it might become a buyer in the years to come.
Philip Skolnick, a spokesman for Genuity Capital Markets, said analysts would like to see figures from the deal to analyze whether EnCana will want to sell off its Deep Panuke project.
"Generally EnCana has prettied assets up and sold them. It makes the asset (Deep Panuke) more attractive to sell because they can say 'look we have a guaranteed buyer of the production,"' Skolnick said.
Both MacLean and Rix said that Repsol could sell a portion of the natural gas to a Nova Scotia buyer, such as Heritage Gas, in order for the fuel to reach residents of the province.
EnCana shares didn't trade Monday because holidays that closed North American stock market.
EnCana spokeswoman Lori MacLean says that the Calgary-based company's contract with Repsol takes effect immediately and will apply for the life of the offshore project, which is slated to begin in late 2010.
The project is proposing to produce 200 million cubic feet of gas per day at startup and will ramp up to 300 million cubic feet daily, roughly enough gas to heat 1,500 homes for one year.
Kristian Rix, a Barcelona-based spokesman for Repsol, said Monday in an interview that his firm believes Canada and the U.S. northeast is a lucrative market, and the company retains a goal of capturing about 20 per cent of sales in the region.
"Here's a chance to get access to more gas, and it allows us to gain market share and grow faster than we'd originally thought we'd be able to," Rix said.
No details of the deal were released.
The gas from near Sable Island, off Nova Scotia's east coast, will be available to ship through the Maritimes and Northeast pipeline to the U.S. and Canadian markets.
Steve Rankin, a spokesman for Maritimes and Northeast, said there's no firm contract in place yet with Repsol to ship over the Canadian portion of the pipeline, but he speculated the owners of the Deep Panuke gas may buy space from other companies that currently use the pipeline.
Meanwhile, Rix said, Repsol is making its first delivery of liquified natural gas by this May to the Canaport terminal near Saint John, N.B.
The joint project between Repsol and New Brunswick-based Irving Oil Ltd. will source its liquefied natural gas from Trinidad and Tobago, among other places, and ship the gas to the terminal through the company's fleet of 11 tankers.
LNG is created by cooling natural gas into a liquid state, making it easier to store and transport to overseas markets via special tankers.
The Canaport project will receive shipments of LNG, convert the liquid back into a gas, and feed it by the underground Brunswick pipeline (TSX:EMA) to the Maritimes and Northeast pipeline in the United States.
Repsol, which holds a 75 per cent stake in the Canaport LNG project, expects the terminal will be able to process one billion cubic feet per day of gas.
The Deep Panuke gas will now serve to fill any gaps in production from the Saint John facilities, he added.
There has been speculation that EnCana might eventually be interested in selling the Deep Panuke field.
Rix said that Repsol isn't commenting on whether it might become a buyer in the years to come.
Philip Skolnick, a spokesman for Genuity Capital Markets, said analysts would like to see figures from the deal to analyze whether EnCana will want to sell off its Deep Panuke project.
"Generally EnCana has prettied assets up and sold them. It makes the asset (Deep Panuke) more attractive to sell because they can say 'look we have a guaranteed buyer of the production,"' Skolnick said.
Both MacLean and Rix said that Repsol could sell a portion of the natural gas to a Nova Scotia buyer, such as Heritage Gas, in order for the fuel to reach residents of the province.
EnCana shares didn't trade Monday because holidays that closed North American stock market.
Monday, February 16, 2009
Natural Gas Prices Down Again
Despite price declines, many consumers have not seen savings on bills
By M.D. KITTLE TH assistant city editor
If there's a silver lining to the clouds of economic gloom and doom, it's that the recession has been such a drag on demand that it's pulled down energy prices.
Natural gas prices continued to plummet Friday, as demand fears sent prices falling for a fifth straight day. With almost spring-like temperatures reported in much of the U.S. in recent weeks and energy consumption in the industrial sector diminished by the stalled economy, natural gas prices in some regions have slid by as much as 40 percent.
In Iowa, prices over the winter heating season to date (November-early February) are down about 9 percent, according to Black Hills Energy, which serves about 41,000 customers in the Dubuque area.
But a lot of consumers might be scratching their heads. The price declines have yet to materialize on average billing statements.
That has a lot to do with how energy providers purchase their heating fuel. Black Hills, formerly Aquila, like its peers, buys much of its natural gas stock months in advance of the winter heating season, a strategy aimed at curbing
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the wild swings of a volatile energy source. The idea is sound; typically prices are much cheaper in summer or early fall than they are on the spot market in the dead of winter -- when demand is at its highest.
But it doesn't always work. Case in point, the last couple of weeks.
"In terms of the prices we locked in at, yes, unfortunately some of those prices are higher than what they are right now," said Alliant Energy spokesman Steve Schultz. "This has been anything but a typical year."
Alliant's average residential natural gas customer in Wisconsin paid about $195 in January, up about 6 percent from January 2008. Much of that increase was driven by demand, with a seemingly endless string of days marked by below-zero temperatures.
The typical Black Hills Energy residential customer in Dubuque paid about $180 last month, and $120 in December, according to company spokesman Brian Ortner. He could not provide pricing comparisons for the same months in the previous year because of the ownership change.
Utilities only pass through energy prices to consumers, they are not to profit from them.
Black Hills Energy's Colorado consumers could see a big natural gas rate break thanks to declining prices on the open market. The energy provider filed a request with the Colorado Public Utilities Commission to cut by 28 percent the cost per unit of natural gas for its residential, commercial and industrial customers. Under the proposal, a typical residential customer would pay about $156, compared to $214 on a monthly bill during peak usage.
Asked if Iowa customers could see a pricing break, Ortner said, "You would hope so." He noted much depends on usage.
Like other energy providers, Alliant purchases about one-third of its natural gas on the spot market, so the lower pricing should eventually be realized in billing statements -- if prolonged cold and, consequently, demand don't push prices back up. Given the state of the economy, odds are demand, on the industrial side at least, should stay down.
The Energy Information Administration projects total natural gas consumption will decline by 1.3 percent in 2009, before seeing a slight increase next year.
Customers on so-called budget billing plans could be seeing red as spot natural gas prices continue to fall. The customers, who pay a consistent rate every month in order to take the volatility out of their monthly bills, in many cases end up paying more as market prices fall.
Black Hills had about 38,000 customers in the program in January.
By M.D. KITTLE TH assistant city editor
If there's a silver lining to the clouds of economic gloom and doom, it's that the recession has been such a drag on demand that it's pulled down energy prices.
Natural gas prices continued to plummet Friday, as demand fears sent prices falling for a fifth straight day. With almost spring-like temperatures reported in much of the U.S. in recent weeks and energy consumption in the industrial sector diminished by the stalled economy, natural gas prices in some regions have slid by as much as 40 percent.
In Iowa, prices over the winter heating season to date (November-early February) are down about 9 percent, according to Black Hills Energy, which serves about 41,000 customers in the Dubuque area.
But a lot of consumers might be scratching their heads. The price declines have yet to materialize on average billing statements.
That has a lot to do with how energy providers purchase their heating fuel. Black Hills, formerly Aquila, like its peers, buys much of its natural gas stock months in advance of the winter heating season, a strategy aimed at curbing
Advertisement
the wild swings of a volatile energy source. The idea is sound; typically prices are much cheaper in summer or early fall than they are on the spot market in the dead of winter -- when demand is at its highest.
But it doesn't always work. Case in point, the last couple of weeks.
"In terms of the prices we locked in at, yes, unfortunately some of those prices are higher than what they are right now," said Alliant Energy spokesman Steve Schultz. "This has been anything but a typical year."
Alliant's average residential natural gas customer in Wisconsin paid about $195 in January, up about 6 percent from January 2008. Much of that increase was driven by demand, with a seemingly endless string of days marked by below-zero temperatures.
The typical Black Hills Energy residential customer in Dubuque paid about $180 last month, and $120 in December, according to company spokesman Brian Ortner. He could not provide pricing comparisons for the same months in the previous year because of the ownership change.
Utilities only pass through energy prices to consumers, they are not to profit from them.
Black Hills Energy's Colorado consumers could see a big natural gas rate break thanks to declining prices on the open market. The energy provider filed a request with the Colorado Public Utilities Commission to cut by 28 percent the cost per unit of natural gas for its residential, commercial and industrial customers. Under the proposal, a typical residential customer would pay about $156, compared to $214 on a monthly bill during peak usage.
Asked if Iowa customers could see a pricing break, Ortner said, "You would hope so." He noted much depends on usage.
Like other energy providers, Alliant purchases about one-third of its natural gas on the spot market, so the lower pricing should eventually be realized in billing statements -- if prolonged cold and, consequently, demand don't push prices back up. Given the state of the economy, odds are demand, on the industrial side at least, should stay down.
The Energy Information Administration projects total natural gas consumption will decline by 1.3 percent in 2009, before seeing a slight increase next year.
Customers on so-called budget billing plans could be seeing red as spot natural gas prices continue to fall. The customers, who pay a consistent rate every month in order to take the volatility out of their monthly bills, in many cases end up paying more as market prices fall.
Black Hills had about 38,000 customers in the program in January.
Sunday, February 15, 2009
Natural Gas Undervalued: Gazprom's Medvedev
By Halia Pavliva
Feb. 13 (Bloomberg) -- Natural gas is undervalued and its price less susceptible to producer influence than oil because long-term contracts dominate the industry, said Alexander Medvedev, deputy chief executive officer of OAO Gazprom.
European consumption of the fuel will probably grow faster than previously forecast, Medvedev said in an interview with Bloomberg News in New York. He said the continent may need an additional 150 billion cubic meters of gas by 2025.
A 15-member group of natural gas producers, which includes Russia, Iran and Qatar and is known as the Gas Exporting Countries Forum, agreed Dec. 23 to coordinate forecasts, investments and relations with consumers in an attempt to bolster their influence in world markets.
“Objectively, natural gas is undervalued,” Medvedev said. “The era of cheap energy is over.”
Natural gas futures on the New York Mercantile Exchange have dropped 21 percent this year and are down 69 percent since a 2008 high of $13.694 per million British thermal units reached July 2. Gas for March delivery fell 0.9 percent today to $4.447 per million Btu at 1:59 p.m. in New York.
Asked about the purpose of the gas-producer group, Medvedev said that “what is really important is to have a dialog with consumers about the fuel and environmental aspects of its use.”
Gas Supply
Medvedev said consumer concerns that the group may seek to influence the gas price were unfounded. “It’s a joke,” he said, adding that long-term contracts prevent manipulation of output. The gas group pumps about 40 percent of global natural-gas supply, and Gazprom is the world’s largest natural-gas producer.
The Organization of Petroleum Exporting Countries, formed in 1960, didn’t gain substantial influence over crude oil prices until the 1973 oil embargo and after U.S. crude output had peaked, Edward Kott, a commodity analyst at Louis Capital, said in a report Feb. 5. OPEC accounts for about 43 percent of global oil output.
The gas price is linked to the price of oil, which is also undervalued, Medvedev said. “Oil at $85 per barrel is more justified than $45 per barrel,” he said.
Crude oil for March delivery surged 10.3 percent to $37.48 a barrel at 1:07 p.m. on the New York Mercantile Exchange. Yesterday, the contract fell 5.5 percent to $33.98, the lowest settlement since Dec. 19. Oil futures are down 19 percent this year.
Output Cuts
Russia, whose major export earner is oil, is not a member of OPEC and the government has repeatedly said it is not planning to become a member of the organization.
Medvedev said that “both weather and technology” make it impossible for Russia to cut oil production when prices fall, as OPEC countries do. “It’s one story to cut oil production in the Middle East, and it’s a totally different story to do so in Siberia,” he said.
The global financial crisis may mean an opportunity for Gazprom to purchase more assets at low prices, including in North America, Medvedev said, declining to comment further. The company may borrow money for the purchases from Russia’s state-owned banks at low interest rates, he said. Before state-run Gazprom, based in Moscow, looks into purchasing more assets, “the dust should settle a little bit,” Medvedev said.
Gazprom is dedicated to secure stable supplies to its consumers in Europe after the supplies via Ukraine were halted for several days in 2006 and again last month, Medvedev said. Gazprom supplies a quarter of European Union gas, 80 percent of which is shipped through Ukrainian territory.
Supply Stability
Ukraine, which sends most of Gazprom’s gas exports to Europe, should initiate a gas consortium with European partners and Gazprom, to guarantee stability of the supplies, Medvedev said. Ukraine pumped 119 billion cubic meters of Russian gas to Europe last year, according to NAK Naftogaz Ukrainy, representing 80 percent of Gazprom’s shipments to the European Union.
“There is no doubt about the stability of Ukraine’s gas transportation system,” said Oleksandr Hudyma, a top energy aide to Prime Minister Yulia Timoshenko, in a phone interview, adding Ukraine’s government objects to Russian proposals for a consortium.
Gazprom, which meets 70 percent of the gas needs of Ukraine, stopped supplies to the neighboring country in January over a price dispute. The conflict caused shortages in 20 European countries for more than two weeks amid freezing temperatures.
Gazprom has no plans to sell its 50 percent stake in Swiss- registered trader RosUkrEnergo AG, which was the sole importer of gas to Ukraine from 2006 and which has now been excluded from that role, Medvedev said. RosUkrEnergo owes Gazprom about $500 million, he said.
Ukrainian billionaire Dmitry Firtash owns 45 percent of RosUkrEnergo and his business partner Ivan Fursin the remaining 5 percent.
To contact the reporters on this story: Halia Pavliva in New York at hpavliva@bloomberg.net; Daryna Krasnolutska in Kiev at dkrasnolutsk@bloomberg.net
Feb. 13 (Bloomberg) -- Natural gas is undervalued and its price less susceptible to producer influence than oil because long-term contracts dominate the industry, said Alexander Medvedev, deputy chief executive officer of OAO Gazprom.
European consumption of the fuel will probably grow faster than previously forecast, Medvedev said in an interview with Bloomberg News in New York. He said the continent may need an additional 150 billion cubic meters of gas by 2025.
A 15-member group of natural gas producers, which includes Russia, Iran and Qatar and is known as the Gas Exporting Countries Forum, agreed Dec. 23 to coordinate forecasts, investments and relations with consumers in an attempt to bolster their influence in world markets.
“Objectively, natural gas is undervalued,” Medvedev said. “The era of cheap energy is over.”
Natural gas futures on the New York Mercantile Exchange have dropped 21 percent this year and are down 69 percent since a 2008 high of $13.694 per million British thermal units reached July 2. Gas for March delivery fell 0.9 percent today to $4.447 per million Btu at 1:59 p.m. in New York.
Asked about the purpose of the gas-producer group, Medvedev said that “what is really important is to have a dialog with consumers about the fuel and environmental aspects of its use.”
Gas Supply
Medvedev said consumer concerns that the group may seek to influence the gas price were unfounded. “It’s a joke,” he said, adding that long-term contracts prevent manipulation of output. The gas group pumps about 40 percent of global natural-gas supply, and Gazprom is the world’s largest natural-gas producer.
The Organization of Petroleum Exporting Countries, formed in 1960, didn’t gain substantial influence over crude oil prices until the 1973 oil embargo and after U.S. crude output had peaked, Edward Kott, a commodity analyst at Louis Capital, said in a report Feb. 5. OPEC accounts for about 43 percent of global oil output.
The gas price is linked to the price of oil, which is also undervalued, Medvedev said. “Oil at $85 per barrel is more justified than $45 per barrel,” he said.
Crude oil for March delivery surged 10.3 percent to $37.48 a barrel at 1:07 p.m. on the New York Mercantile Exchange. Yesterday, the contract fell 5.5 percent to $33.98, the lowest settlement since Dec. 19. Oil futures are down 19 percent this year.
Output Cuts
Russia, whose major export earner is oil, is not a member of OPEC and the government has repeatedly said it is not planning to become a member of the organization.
Medvedev said that “both weather and technology” make it impossible for Russia to cut oil production when prices fall, as OPEC countries do. “It’s one story to cut oil production in the Middle East, and it’s a totally different story to do so in Siberia,” he said.
The global financial crisis may mean an opportunity for Gazprom to purchase more assets at low prices, including in North America, Medvedev said, declining to comment further. The company may borrow money for the purchases from Russia’s state-owned banks at low interest rates, he said. Before state-run Gazprom, based in Moscow, looks into purchasing more assets, “the dust should settle a little bit,” Medvedev said.
Gazprom is dedicated to secure stable supplies to its consumers in Europe after the supplies via Ukraine were halted for several days in 2006 and again last month, Medvedev said. Gazprom supplies a quarter of European Union gas, 80 percent of which is shipped through Ukrainian territory.
Supply Stability
Ukraine, which sends most of Gazprom’s gas exports to Europe, should initiate a gas consortium with European partners and Gazprom, to guarantee stability of the supplies, Medvedev said. Ukraine pumped 119 billion cubic meters of Russian gas to Europe last year, according to NAK Naftogaz Ukrainy, representing 80 percent of Gazprom’s shipments to the European Union.
“There is no doubt about the stability of Ukraine’s gas transportation system,” said Oleksandr Hudyma, a top energy aide to Prime Minister Yulia Timoshenko, in a phone interview, adding Ukraine’s government objects to Russian proposals for a consortium.
Gazprom, which meets 70 percent of the gas needs of Ukraine, stopped supplies to the neighboring country in January over a price dispute. The conflict caused shortages in 20 European countries for more than two weeks amid freezing temperatures.
Gazprom has no plans to sell its 50 percent stake in Swiss- registered trader RosUkrEnergo AG, which was the sole importer of gas to Ukraine from 2006 and which has now been excluded from that role, Medvedev said. RosUkrEnergo owes Gazprom about $500 million, he said.
Ukrainian billionaire Dmitry Firtash owns 45 percent of RosUkrEnergo and his business partner Ivan Fursin the remaining 5 percent.
To contact the reporters on this story: Halia Pavliva in New York at hpavliva@bloomberg.net; Daryna Krasnolutska in Kiev at dkrasnolutsk@bloomberg.net
Saturday, February 14, 2009
New Mexico Natural Gas Deal
DULCE, N.M. (AP) - The Jicarilla Apache Nation has signed a 20-year right of way agreement with a subsidiary of Williams Partners, providing incentives to expand natural gas operations on the reservation.
Jicarilla president Levi Pesata said Thursday the deal will provide "a stable and significant source of money" for the northern New Mexico tribe.
Provisions of the agreement include recognition that sensitive religious, cultural and pristine sites will be off-limits to development. The company also agreed to provide education and training programs and employment for tribal members.
The deal also gives the Jicarillas a future option to convert the agreement into a joint venture.
(Copyright 2009 by The Associated Press. All Rights Reserved.)
Jicarilla president Levi Pesata said Thursday the deal will provide "a stable and significant source of money" for the northern New Mexico tribe.
Provisions of the agreement include recognition that sensitive religious, cultural and pristine sites will be off-limits to development. The company also agreed to provide education and training programs and employment for tribal members.
The deal also gives the Jicarillas a future option to convert the agreement into a joint venture.
(Copyright 2009 by The Associated Press. All Rights Reserved.)
Friday, February 13, 2009
Spanish Natural Gas Oks Gas Natural
By Robert Hetz and Jonathan Gleave
MADRID, Feb 12 (Reuters) - Spanish competition authority CNC has approved Gas Natural's (GAS.MC: Quote, Profile, Research) 16.7 billion euro ($21.6 billion) bid for utility Union Fenosa (UNF.MC: Quote, Profile, Research) with conditions proposed by the gas company, the regulator said on Thursday.
Gas Natural will not be obliged to sell Fenosa's 50 percent stake in the gas business the power company runs jointly with Italy's ENI (ENI.MI: Quote, Profile, Research), but must guarantee the autonomy of Union Fenosa Gas in supplying third parties in Spain.
Gas Natural said on Tuesday that it would not consent to the sale of the gas business, whose 6.4 billion cubic metres (BCM) of gas would put the company well on its way to achieving targets to boost its own portfolio by 9 BCM in 2012.
The CNC said that Gas Natural must sell 600,000 gas supply points, equal to 9 percent of its total in Spain, dispose of 600,000 small gas clients and sell 2,000 megawatts of installed capacity at combined cycle plants.
The CNC also said Gas Natural is committed to selling its stake in Enagas (ENAG.MC: Quote, Profile, Research) and reduce its links to Cepsa (CEP.MC: Quote, Profile, Research) by standing down from the oil group's board to avoid competition issues with Repsol (REP.MC: Quote, Profile, Research).
"The proposed divestments do not affect the reasoning behind the operation or the model of gas and electricity integration," Gas Natural said in a press note following the announcement.
Gas Natural shares closed down 1.35 percent at 16.79 euros, while Union Fenosa was up 0.63 percent at 17.66. Madrid's IBEX35 share index .IBEX closed down 1.85 percent.
Once the economy ministry has approved the bid conditions, which could happen after Friday's cabinet meeting, Gas Natural will buy the 35 percent of Fenosa still owned by ACS (ACS.MC: Quote, Profile, Research).
The acquisition will take its stake in Fenosa to 50 percent, and trigger a mandatory full bid for the power company at 18.05 euros per share, which Gas Natural has said it hopes to complete in April.
The gas company will meanwhile ask shareholders on March 10 for financial backing for the deal in the form of a 3.5 billion euro rights issue, which core shareholders oil company Repsol (REP.MC: Quote, Profile, Research) and savings bank La Caixa have fully underwritten.
Gas Natural also plans to part-finance the deal from 3 billion euros of asset sales, including any disposals mandated by the CNC.
The asset sale and rights issue should help to reduce Gas Natural's dependence on the 18.5 billion euro credit line it secured for the Fenosa purchase. Its total debt stood at 4.9 billion euros in December 2008.
(Reporting by Jonathan Gleave and Robert Hetz; additional reporting by Paul Day; editing Bernard Orr)
MADRID, Feb 12 (Reuters) - Spanish competition authority CNC has approved Gas Natural's (GAS.MC: Quote, Profile, Research) 16.7 billion euro ($21.6 billion) bid for utility Union Fenosa (UNF.MC: Quote, Profile, Research) with conditions proposed by the gas company, the regulator said on Thursday.
Gas Natural will not be obliged to sell Fenosa's 50 percent stake in the gas business the power company runs jointly with Italy's ENI (ENI.MI: Quote, Profile, Research), but must guarantee the autonomy of Union Fenosa Gas in supplying third parties in Spain.
Gas Natural said on Tuesday that it would not consent to the sale of the gas business, whose 6.4 billion cubic metres (BCM) of gas would put the company well on its way to achieving targets to boost its own portfolio by 9 BCM in 2012.
The CNC said that Gas Natural must sell 600,000 gas supply points, equal to 9 percent of its total in Spain, dispose of 600,000 small gas clients and sell 2,000 megawatts of installed capacity at combined cycle plants.
The CNC also said Gas Natural is committed to selling its stake in Enagas (ENAG.MC: Quote, Profile, Research) and reduce its links to Cepsa (CEP.MC: Quote, Profile, Research) by standing down from the oil group's board to avoid competition issues with Repsol (REP.MC: Quote, Profile, Research).
"The proposed divestments do not affect the reasoning behind the operation or the model of gas and electricity integration," Gas Natural said in a press note following the announcement.
Gas Natural shares closed down 1.35 percent at 16.79 euros, while Union Fenosa was up 0.63 percent at 17.66. Madrid's IBEX35 share index .IBEX closed down 1.85 percent.
Once the economy ministry has approved the bid conditions, which could happen after Friday's cabinet meeting, Gas Natural will buy the 35 percent of Fenosa still owned by ACS (ACS.MC: Quote, Profile, Research).
The acquisition will take its stake in Fenosa to 50 percent, and trigger a mandatory full bid for the power company at 18.05 euros per share, which Gas Natural has said it hopes to complete in April.
The gas company will meanwhile ask shareholders on March 10 for financial backing for the deal in the form of a 3.5 billion euro rights issue, which core shareholders oil company Repsol (REP.MC: Quote, Profile, Research) and savings bank La Caixa have fully underwritten.
Gas Natural also plans to part-finance the deal from 3 billion euros of asset sales, including any disposals mandated by the CNC.
The asset sale and rights issue should help to reduce Gas Natural's dependence on the 18.5 billion euro credit line it secured for the Fenosa purchase. Its total debt stood at 4.9 billion euros in December 2008.
(Reporting by Jonathan Gleave and Robert Hetz; additional reporting by Paul Day; editing Bernard Orr)
Thursday, February 12, 2009
Natural Gas Vehicle Incentives Advocated to Congress
By ELIZABETH SOUDER / The Dallas Morning News
esouder@dallasnews.com
HOUSTON -- Chesapeake Energy Corp. chief executive Aubrey McClendon wants Americans to use more of his product, natural gas.
McClendon is pushing federal lawmakers to offer incentives for natural gas vehicles and to regulate carbon dioxide emissions. Most experts say natural gas, which emits less carbon dioxide than coal, could gain market share if Congress limits greenhouse gas emissions.
“I guess my real dream here is that we begin to transition our transport network away from products that are based on oil and replace that with a fuel that’s made in America,” McClendon said after a speech to the Cambridge Energy Research Associates conference on Wednesday.
He’s pitching natural gas as plentiful, thanks to drilling in four shale fields in the U.S., including the Barnett Shale. Chesapeake is the No. 2 producer of the Barnett Shale field in North Texas.
Those shale fields have boosted production beyond demand in the past year, contributing to a sharp decline in natural gas prices. McClendon said the shale fields are so rich and relatively cheap to produce, they could begin to crowd out production in older, conventional natural gas fields.
If natural gas prices are around $5 per million British thermal units, shale production can be profitable, he said. But prices need to be range of $8 to $9 per million Btu to keep total U.S. production steady, he added.
For now, he said, the industry must cut production to boost prices to a profitable level. He said the decline in the number of working rigs in the U.S. should do it.
“I think we’ll transition into 2010 with a lot peppier gas price than we have today,” McClendon said.
He’s also positioning his product as clean.
“We want to reposition natural gas as the best-known alternative fuel in the United States,” he said, adding: “Not as an alternative to fossil fuels. It will always be hard to get beyond the molecular origin of our fuel.”
So far, McClendon said, President Barack Obama's administration is listening. But the government hasn’t passed new laws to benefit natural gas.
One problem with using more natural gas is that prices are volatile. Texas wholesale power prices follow natural gas prices, and both have put consumers on a roller coaster the past few years.
Most energy executives say price volatility is a killer for both consumers and the industry. No one can predict what their costs or profit will be when prices go up and down.
McClendon, ever the maverick, said he likes volatility. His company has the expertise to protect itself with complicated financial trades, called hedges, giving him an advantage over other natural gas producers.
“It’s a way for us to make additional money,” he said.
Further, he said, natural gas isn’t to blame for high electricity prices in Texas. The problem is the way the Legislature set up the market, he said.
The least efficient power plant operating at any given time sets the electricity price for the entire Texas spot market. That plant is almost always a natural gas plant, so his fuel gets blamed for the problem, McClendon said. New, efficient natural gas plants can generate power as cheaply as some coal plants, he said.
"To price the whole stack of electricity by the least efficient generator is a crazy way to do it," he said.
esouder@dallasnews.com
HOUSTON -- Chesapeake Energy Corp. chief executive Aubrey McClendon wants Americans to use more of his product, natural gas.
McClendon is pushing federal lawmakers to offer incentives for natural gas vehicles and to regulate carbon dioxide emissions. Most experts say natural gas, which emits less carbon dioxide than coal, could gain market share if Congress limits greenhouse gas emissions.
“I guess my real dream here is that we begin to transition our transport network away from products that are based on oil and replace that with a fuel that’s made in America,” McClendon said after a speech to the Cambridge Energy Research Associates conference on Wednesday.
He’s pitching natural gas as plentiful, thanks to drilling in four shale fields in the U.S., including the Barnett Shale. Chesapeake is the No. 2 producer of the Barnett Shale field in North Texas.
Those shale fields have boosted production beyond demand in the past year, contributing to a sharp decline in natural gas prices. McClendon said the shale fields are so rich and relatively cheap to produce, they could begin to crowd out production in older, conventional natural gas fields.
If natural gas prices are around $5 per million British thermal units, shale production can be profitable, he said. But prices need to be range of $8 to $9 per million Btu to keep total U.S. production steady, he added.
For now, he said, the industry must cut production to boost prices to a profitable level. He said the decline in the number of working rigs in the U.S. should do it.
“I think we’ll transition into 2010 with a lot peppier gas price than we have today,” McClendon said.
He’s also positioning his product as clean.
“We want to reposition natural gas as the best-known alternative fuel in the United States,” he said, adding: “Not as an alternative to fossil fuels. It will always be hard to get beyond the molecular origin of our fuel.”
So far, McClendon said, President Barack Obama's administration is listening. But the government hasn’t passed new laws to benefit natural gas.
One problem with using more natural gas is that prices are volatile. Texas wholesale power prices follow natural gas prices, and both have put consumers on a roller coaster the past few years.
Most energy executives say price volatility is a killer for both consumers and the industry. No one can predict what their costs or profit will be when prices go up and down.
McClendon, ever the maverick, said he likes volatility. His company has the expertise to protect itself with complicated financial trades, called hedges, giving him an advantage over other natural gas producers.
“It’s a way for us to make additional money,” he said.
Further, he said, natural gas isn’t to blame for high electricity prices in Texas. The problem is the way the Legislature set up the market, he said.
The least efficient power plant operating at any given time sets the electricity price for the entire Texas spot market. That plant is almost always a natural gas plant, so his fuel gets blamed for the problem, McClendon said. New, efficient natural gas plants can generate power as cheaply as some coal plants, he said.
"To price the whole stack of electricity by the least efficient generator is a crazy way to do it," he said.
Wednesday, February 11, 2009
EIA 2009 Natural Gas Forecast
Adds details on gas consumption, production, price estimates)
NEW YORK, Feb 10 (Reuters) - The U.S. Energy Information Administration on Tuesday again cut its estimate of domestic natural gas production growth in 2009 and further increased the expected decline in demand as economic activity continues to slow.
In its February Short-Term Energy Outlook, EIA forecast U.S. marketed natural gas output this year would rise 0.13 billion cubic feet per day to 58.73 bcf daily, up 0.2 percent from last year but down slightly from a 0.7 percent gain forecast in its previous monthly report.
In 2010, EIA said total U.S. marketed natural gas production was expected to decline 1.1 percent, as producers continue to slow development due to lower gas prices.
EIA said some production curtailments may be necessary later in 2009 to balance an oversupplied market.
EIA also projected domestic gas consumption this year would fall 0.85 bcf per day, or 1.3 percent, to 62.70 bcf per day, more than the 1 percent drop forecast last month.
EIA said expectations for weather-driven consumption growth in the residential and commercial sectors this year were outweighed by the implications of continued economic weakness in the industrial and electric power sectors.
Demand from the industrial sector alone was projected to fall 5.1 percent this year, up from last month's estimate of a 3 percent decline.
EIA expects consumption next year to grow slightly by 0.6 percent, primarily due to gains from the electric power sector, but that estimate too was down from the 0.7 percent gain forecast in its previous short-term outlook.
NEW YORK, Feb 10 (Reuters) - The U.S. Energy Information Administration on Tuesday again cut its estimate of domestic natural gas production growth in 2009 and further increased the expected decline in demand as economic activity continues to slow.
In its February Short-Term Energy Outlook, EIA forecast U.S. marketed natural gas output this year would rise 0.13 billion cubic feet per day to 58.73 bcf daily, up 0.2 percent from last year but down slightly from a 0.7 percent gain forecast in its previous monthly report.
In 2010, EIA said total U.S. marketed natural gas production was expected to decline 1.1 percent, as producers continue to slow development due to lower gas prices.
EIA said some production curtailments may be necessary later in 2009 to balance an oversupplied market.
EIA also projected domestic gas consumption this year would fall 0.85 bcf per day, or 1.3 percent, to 62.70 bcf per day, more than the 1 percent drop forecast last month.
EIA said expectations for weather-driven consumption growth in the residential and commercial sectors this year were outweighed by the implications of continued economic weakness in the industrial and electric power sectors.
Demand from the industrial sector alone was projected to fall 5.1 percent this year, up from last month's estimate of a 3 percent decline.
EIA expects consumption next year to grow slightly by 0.6 percent, primarily due to gains from the electric power sector, but that estimate too was down from the 0.7 percent gain forecast in its previous short-term outlook.
Tuesday, February 10, 2009
Natural Gas Car by Mercedes Benz
Washington--According to Mercedes-Benz, it is thinking of selling a vehicle fueled by natural gas in the United States.
Mercedes, part of Daimler AG, displayed a B-class model that can run on compressed natural gas last week at the Washington Auto Show.
William Craven, general manager of regulatory affairs for Daimler's Washington office, confirmed the company's interest in testing the market for natural-gas-powered vehicles in the United States.
At a green-car conference before the Washington show, Craven and other industry leaders said many options to gasoline-powered vehicles exist, and all need to be used. Most conference participants argued against government choosing a single solution to the problems of over reliance on petroleum and the automobile's role in the threat of climate change.
Johan de Nysschen, president of Audi of America, warned that government pressure on the Big 3 to focus on plug-in hybrids could be the death knell for the companies. He said the companies could end up trying to sell vehicles that don't make economic sense.
Natural gas once was considered a promising alternative fuel but has fallen out of favor in the light-duty segment.
(Source: Automotive News)
Mercedes, part of Daimler AG, displayed a B-class model that can run on compressed natural gas last week at the Washington Auto Show.
William Craven, general manager of regulatory affairs for Daimler's Washington office, confirmed the company's interest in testing the market for natural-gas-powered vehicles in the United States.
At a green-car conference before the Washington show, Craven and other industry leaders said many options to gasoline-powered vehicles exist, and all need to be used. Most conference participants argued against government choosing a single solution to the problems of over reliance on petroleum and the automobile's role in the threat of climate change.
Johan de Nysschen, president of Audi of America, warned that government pressure on the Big 3 to focus on plug-in hybrids could be the death knell for the companies. He said the companies could end up trying to sell vehicles that don't make economic sense.
Natural gas once was considered a promising alternative fuel but has fallen out of favor in the light-duty segment.
(Source: Automotive News)
Monday, February 9, 2009
New Natural Gas Pipeline for Washington State
Saturday, February 7 | 11:21 p.m.
BY MICHAEL ANDERSEN
COLUMBIAN STAFF WRITER
A company that pipes natural gas into Clark County is pushing forward a plan to run a new pipeline up the Columbia Gorge and into the Hockinson area.
The new line would largely run alongside Williams Pipeline’s existing pipe, which starts in Stanfield, Ore., and runs along the north side of the Columbia River, passing north of Washougal to meet Interstate 5 near La Center.
However, the new pipeline would only go as far west as the center of Clark County, not clear to La Center.
Williams suspended fieldwork on the proposal, called the Blue Bridge Pipeline, in November. But on Tuesday, company officials plan to ask county commissioners for permission to begin surveying a possible route through county-run Camp Bonneville.
Williams hasn’t yet resumed fieldwork, Williams spokeswoman Michele Swaner said Friday. But the company may be preparing to do so.
"We are moving ahead on it," Swaner said.
In May and June, she said, the company will hold five public open houses on the proposed line in Clark, Skamania, Klickitat, Benton and Lewis counties.
Specific maps of the new route should be available later in the spring, Swaner said.
The new 30-inch or 36-inch natural gas pipe through the Gorge is supposed to begin service by Fall 2012.
If it does, more natural gas could reach the I-5 corridor, including the Portland area. The area’s only other source is a pipeline running south from Canada, Swaner said.
A new 182-mile pipeline could move up to 500 million cubic feet of natural gas per day, said Lori Volkman, Clark County’s lawyer on the issue.
But if the pipeline is to be built, Volkman said, current plans show that it would need the county’s permission. That’s because the new route would require a 75-foot-wide easement across Camp Bonneville.
Volkman said the current easement is 70 feet wide.
For more information, including a large-scale map of the pipeline route, visit www.bluebridgepipeline.com.
Michael Andersen: 360-735-4508 or michael.andersen@columbian.com.
BY MICHAEL ANDERSEN
COLUMBIAN STAFF WRITER
A company that pipes natural gas into Clark County is pushing forward a plan to run a new pipeline up the Columbia Gorge and into the Hockinson area.
The new line would largely run alongside Williams Pipeline’s existing pipe, which starts in Stanfield, Ore., and runs along the north side of the Columbia River, passing north of Washougal to meet Interstate 5 near La Center.
However, the new pipeline would only go as far west as the center of Clark County, not clear to La Center.
Williams suspended fieldwork on the proposal, called the Blue Bridge Pipeline, in November. But on Tuesday, company officials plan to ask county commissioners for permission to begin surveying a possible route through county-run Camp Bonneville.
Williams hasn’t yet resumed fieldwork, Williams spokeswoman Michele Swaner said Friday. But the company may be preparing to do so.
"We are moving ahead on it," Swaner said.
In May and June, she said, the company will hold five public open houses on the proposed line in Clark, Skamania, Klickitat, Benton and Lewis counties.
Specific maps of the new route should be available later in the spring, Swaner said.
The new 30-inch or 36-inch natural gas pipe through the Gorge is supposed to begin service by Fall 2012.
If it does, more natural gas could reach the I-5 corridor, including the Portland area. The area’s only other source is a pipeline running south from Canada, Swaner said.
A new 182-mile pipeline could move up to 500 million cubic feet of natural gas per day, said Lori Volkman, Clark County’s lawyer on the issue.
But if the pipeline is to be built, Volkman said, current plans show that it would need the county’s permission. That’s because the new route would require a 75-foot-wide easement across Camp Bonneville.
Volkman said the current easement is 70 feet wide.
For more information, including a large-scale map of the pipeline route, visit www.bluebridgepipeline.com.
Michael Andersen: 360-735-4508 or michael.andersen@columbian.com.
Sunday, February 8, 2009
When Natural Gas Prices Down, Some Wells Shut Down
Even as the national economy went into a tailspin, resource-rich towns like Parachute, Colo., were doing fine. Then natural gas prices began to plunge, and the pain began to rise.
By Nicholas Riccardi - Los Angeles Times - www.latimes.com
February 7, 2009
Reporting from Parachute, Colo. -- Robert Knight was about to install wireless transmitters on eight new drilling rigs joining the thousands that dot the ravines and mesas here when he got the startling news: All but one of the rigs were coming down.
Falling natural gas prices had led energy firms to abruptly curtail their work here last month, battering the last sector of the U.S. economy that had prospered despite the recession.
"Boy, it was quick," said Knight, who has a business installing communication equipment and who serves as the town manager. "It was like the difference between night and day."
The sky-high oil and natural gas prices that burdened consumers during much of the decade were a blessing to residents of this tiny town and other energy-rich communities from Alaska to Arkansas. Even as the national economy went into a tailspin in early 2008, home prices in boomtowns like Parachute kept rising and the streets were packed with shiny new pickups.
But prices suddenly began to drop in September -- natural gas is down 50% from its peak and oil has plummeted from a high of $136 per barrel to about $40.
The plunge brought some relief to recession-racked consumers, but has raised anxieties in Parachute, a town of 1,500 that bears the scars of busts that followed previous energy booms.
In better times, "you couldn't find a hotel room, you couldn't find a campground, you couldn't find a place to rent," said Laura Diaz, the town planning clerk. That's changing fast.
"On Christmas Day there were three U-Hauls in my neighborhood," she said. "It is a little frightening for the people who have been here and know the history."
According to the energy service company Baker Hughes, the number of active oil and gas drilling rigs in the U.S. has dropped 13% since its peak in August. Gary Flaharty, the company's director of investor relations, said the decline matches the industry's response to previous price drops.
Energy experts say the state of the economy could prolong this energy downturn. "The boom, absolutely, is over for the moment," said Pete Stark, vice president for industry relations at IHS in Englewood, Colo.
But energy-rich communities still have stronger economies than much of the rest of the nation. The seven states with budget surpluses can thank the energy industry, said Arturo Perez, a budget analyst with the National Conference of State Legislatures. Wyoming posts the nation's lowest unemployment rate, 3.4% -- less than half the national rate.
Nonetheless, the reversal has been striking.
Last summer, New Mexico held a special legislative session to spend a $200-million surplus fueled partly by energy revenue. Now it is scrambling to close a $400-million deficit.
Alaska, which socked away billions in oil revenue over the last decade, warns that unless oil prices rise, it will face a budget deficit.
In Parachute, 200 miles west of Denver, the change has been dramatic. The town straddles I-70 along the Colorado River, in the shadow of massive mesas and buttes.
On the slope of one mesa sits a subdivision of about 5,000 people that relies on Parachute businesses. Built to house expected oil and gas workers in the 1980s, the development emptied out when the energy industry killed oil shale exploration in the Grand Valley in 1982.
It had filled back up by this decade, as high natural gas prices made exploration in the rugged land of the Piceance Basin economically feasible. The streets of Parachute and similar towns were clogged with flatbed trucks hauling drilling equipment. Hotels were booked for months in advance.
The region barely felt the recession that followed the dot-com bust in 2001, the recovery that followed, or the brutal downturn that began in late 2007.
"We've had an economic bubble over us for some time," Knight said. "We've been pretty well sheltered."
Then in December, it all changed. Rumors began circulating about energy companies cutting jobs. "For Rent" notices appeared on homes and in local newspapers. Three hotel projects were put on hold, and the few existing hotels began to post vacancies.
"We were known as the only one-stoplight town that had a traffic congestion issue," Knight said. "Compared to that, it's almost like a ghost town."
At VJ's Outlaw Ribbs, the regular flow of customers slowed to a trickle. Some began stopping in to say goodbye -- they'd been laid off and were heading back to their home states of Texas, Louisiana and elsewhere.
"People we used to see every day, we just don't see anymore," said waitress Lori Ross. She tried to look on the bright side -- when she rented a house last year there were 50 applications per open rental. Now, she said, "there are rentals everywhere."
Last week, Del Dawson, a local real estate agent, did what had been unthinkable in Parachute for several years: He cut the prices on two homes.
Like some other local business leaders, Dawson remains optimistic about the region's long-term prospects. He expects energy firms to redouble their efforts when the price of gas creeps back up -- local expectations are that will happen this summer or spring 2010. And many companies are maintaining a sizable workforce for their already drilled wells.
"We still feel it's a boom," said Hayden Rader, a developer who has two projects underway in Parachute. "People are saying there's not enough work here, but we've still got more than anyone else."
Yet residents are feeling the pain. Amy Beasley and her husband run the Old Mountain Gift & Jewelry store downtown and a neighboring shipping business. Their revenue has fallen this month, and people they know in the energy industry who had talked about an unending boom have abruptly lost their jobs.
A fourth-generation Parachute native, Beasley, 35, has been ambivalent about the industry that keeps the town alive but has industrialized the wild lands where her family homesteaded. She and her husband have discussed whether to close their shops given the severity of the downturn.
"We're going to stick it out and try to weather the storm," she said. "It may slow down for a few years, but it's going to be back. They're never going to leave us alone."
nicholas.riccardi@latimes.com
By Nicholas Riccardi - Los Angeles Times - www.latimes.com
February 7, 2009
Reporting from Parachute, Colo. -- Robert Knight was about to install wireless transmitters on eight new drilling rigs joining the thousands that dot the ravines and mesas here when he got the startling news: All but one of the rigs were coming down.
Falling natural gas prices had led energy firms to abruptly curtail their work here last month, battering the last sector of the U.S. economy that had prospered despite the recession.
"Boy, it was quick," said Knight, who has a business installing communication equipment and who serves as the town manager. "It was like the difference between night and day."
The sky-high oil and natural gas prices that burdened consumers during much of the decade were a blessing to residents of this tiny town and other energy-rich communities from Alaska to Arkansas. Even as the national economy went into a tailspin in early 2008, home prices in boomtowns like Parachute kept rising and the streets were packed with shiny new pickups.
But prices suddenly began to drop in September -- natural gas is down 50% from its peak and oil has plummeted from a high of $136 per barrel to about $40.
The plunge brought some relief to recession-racked consumers, but has raised anxieties in Parachute, a town of 1,500 that bears the scars of busts that followed previous energy booms.
In better times, "you couldn't find a hotel room, you couldn't find a campground, you couldn't find a place to rent," said Laura Diaz, the town planning clerk. That's changing fast.
"On Christmas Day there were three U-Hauls in my neighborhood," she said. "It is a little frightening for the people who have been here and know the history."
According to the energy service company Baker Hughes, the number of active oil and gas drilling rigs in the U.S. has dropped 13% since its peak in August. Gary Flaharty, the company's director of investor relations, said the decline matches the industry's response to previous price drops.
Energy experts say the state of the economy could prolong this energy downturn. "The boom, absolutely, is over for the moment," said Pete Stark, vice president for industry relations at IHS in Englewood, Colo.
But energy-rich communities still have stronger economies than much of the rest of the nation. The seven states with budget surpluses can thank the energy industry, said Arturo Perez, a budget analyst with the National Conference of State Legislatures. Wyoming posts the nation's lowest unemployment rate, 3.4% -- less than half the national rate.
Nonetheless, the reversal has been striking.
Last summer, New Mexico held a special legislative session to spend a $200-million surplus fueled partly by energy revenue. Now it is scrambling to close a $400-million deficit.
Alaska, which socked away billions in oil revenue over the last decade, warns that unless oil prices rise, it will face a budget deficit.
In Parachute, 200 miles west of Denver, the change has been dramatic. The town straddles I-70 along the Colorado River, in the shadow of massive mesas and buttes.
On the slope of one mesa sits a subdivision of about 5,000 people that relies on Parachute businesses. Built to house expected oil and gas workers in the 1980s, the development emptied out when the energy industry killed oil shale exploration in the Grand Valley in 1982.
It had filled back up by this decade, as high natural gas prices made exploration in the rugged land of the Piceance Basin economically feasible. The streets of Parachute and similar towns were clogged with flatbed trucks hauling drilling equipment. Hotels were booked for months in advance.
The region barely felt the recession that followed the dot-com bust in 2001, the recovery that followed, or the brutal downturn that began in late 2007.
"We've had an economic bubble over us for some time," Knight said. "We've been pretty well sheltered."
Then in December, it all changed. Rumors began circulating about energy companies cutting jobs. "For Rent" notices appeared on homes and in local newspapers. Three hotel projects were put on hold, and the few existing hotels began to post vacancies.
"We were known as the only one-stoplight town that had a traffic congestion issue," Knight said. "Compared to that, it's almost like a ghost town."
At VJ's Outlaw Ribbs, the regular flow of customers slowed to a trickle. Some began stopping in to say goodbye -- they'd been laid off and were heading back to their home states of Texas, Louisiana and elsewhere.
"People we used to see every day, we just don't see anymore," said waitress Lori Ross. She tried to look on the bright side -- when she rented a house last year there were 50 applications per open rental. Now, she said, "there are rentals everywhere."
Last week, Del Dawson, a local real estate agent, did what had been unthinkable in Parachute for several years: He cut the prices on two homes.
Like some other local business leaders, Dawson remains optimistic about the region's long-term prospects. He expects energy firms to redouble their efforts when the price of gas creeps back up -- local expectations are that will happen this summer or spring 2010. And many companies are maintaining a sizable workforce for their already drilled wells.
"We still feel it's a boom," said Hayden Rader, a developer who has two projects underway in Parachute. "People are saying there's not enough work here, but we've still got more than anyone else."
Yet residents are feeling the pain. Amy Beasley and her husband run the Old Mountain Gift & Jewelry store downtown and a neighboring shipping business. Their revenue has fallen this month, and people they know in the energy industry who had talked about an unending boom have abruptly lost their jobs.
A fourth-generation Parachute native, Beasley, 35, has been ambivalent about the industry that keeps the town alive but has industrialized the wild lands where her family homesteaded. She and her husband have discussed whether to close their shops given the severity of the downturn.
"We're going to stick it out and try to weather the storm," she said. "It may slow down for a few years, but it's going to be back. They're never going to leave us alone."
nicholas.riccardi@latimes.com
Saturday, February 7, 2009
Natural Gas Prices at Bottom?
Natural Gas Pains
Joseph Hargett, Option Advisor, 02.06.09, 02:20 PM EST
Options players can cash in on the overall weakness in the sector by loading up on some put options.
According to the latest data from the Labor Department, the U.S. economy just experienced its worst month of job losses since 1974. The economic report only underscored the growing problem that energy providers are facing in the current market: falling demand and falling prices.
In fact, natural gas prices have plummeted throughout the recession, plunging more than 66% from a high of $13.69 per million British thermal units (BTU) in July 2008 to approximately $4.60 per million BTU on Friday.
Volatility creates money-making opportunities. Click here for a free trial of Bernie Schaeffer's Option Advisor with daily trading recommendations and intraday updates.
What's more, the AMEX Natural Gas Index (XNG) has paced the decline in natural gas futures, giving back more than 48% since July 2008. During this time frame, the index has fought a losing battle with resistance at its 10-week and 20-week moving averages. Furthermore, the 20-week moving average has descended into the psychologically important 400 region, an area that has held the XNG in check since early December.
Despite this poor price action, options traders are betting heavily that the sector has formed a bottom. Specifically, the composite Schaeffer's put/call open interest ratio (SOIR) for XNG components rests at 0.56, in the 36th percentile of its annual range. Furthermore, only 7% of the 98 analysts covering natural gas stocks rate them a "sell."
Should energy prices continue to deteriorate in the midst of this economic turmoil, we could see this bullish sentiment unwind in the form of added selling pressure for the natural gas sector.
Joseph Hargett, Option Advisor, 02.06.09, 02:20 PM EST
Options players can cash in on the overall weakness in the sector by loading up on some put options.
According to the latest data from the Labor Department, the U.S. economy just experienced its worst month of job losses since 1974. The economic report only underscored the growing problem that energy providers are facing in the current market: falling demand and falling prices.
In fact, natural gas prices have plummeted throughout the recession, plunging more than 66% from a high of $13.69 per million British thermal units (BTU) in July 2008 to approximately $4.60 per million BTU on Friday.
Volatility creates money-making opportunities. Click here for a free trial of Bernie Schaeffer's Option Advisor with daily trading recommendations and intraday updates.
What's more, the AMEX Natural Gas Index (XNG) has paced the decline in natural gas futures, giving back more than 48% since July 2008. During this time frame, the index has fought a losing battle with resistance at its 10-week and 20-week moving averages. Furthermore, the 20-week moving average has descended into the psychologically important 400 region, an area that has held the XNG in check since early December.
Despite this poor price action, options traders are betting heavily that the sector has formed a bottom. Specifically, the composite Schaeffer's put/call open interest ratio (SOIR) for XNG components rests at 0.56, in the 36th percentile of its annual range. Furthermore, only 7% of the 98 analysts covering natural gas stocks rate them a "sell."
Should energy prices continue to deteriorate in the midst of this economic turmoil, we could see this bullish sentiment unwind in the form of added selling pressure for the natural gas sector.
Friday, February 6, 2009
Natural Gas Inventory Down
NEW YORK -- U.S. natural gas inventories fell by 195 billion cubic feet in the week ended Jan. 30, the Energy Information Administration reported Thursday. Analysts at IHS Global Insight had expected a drawdown of 221 billion cubic feet. At 2,179 billion cubic feet, stocks were 60 billion cubic feet higher than last year at this time and 17 billion cubic feet above the five-year average, the EIA reported. After the data, March natural gas futures rose 1.1% to $4.641 per million British thermal units.
Copyright © 2009 MarketWatch, Inc.
Copyright © 2009 MarketWatch, Inc.
Thursday, February 5, 2009
Corning Natural Gas Coming to Pennsylvania
Corning Natural Gas Corporation has completed a major pipeline project into Pennsylvania that will bring Marcellus Shale gas to its customers.
Corning Natural Gas President Mike German said the project was the company’s largest single expansion in a quarter-century and would bring significant quantities of competitively priced gas to the utility’s customers.
Jerry Sleve, administrative vice president for the utility company, said “the combination of new local supplies and falling wholesale prices should result in much lower gas prices for our customers in the future.”
CNG’s new pipeline interconnects with a producer’s gathering line in Jackson Township, Pennsylvania.
“Given the Marcellus Shale prospects in our New York State service territory, CNG is hopeful of connecting more local production,” Sleve said, “More local production would likely put further downward pressure on gas prices, thereby helping not only core residential and commercial customers, but also providing a competitive advantage to local industries.”
German said that, “connecting local production is becoming a significant business opportunity for the company and we look forward to similar projects in the future.”
Corning Natural Gas President Mike German said the project was the company’s largest single expansion in a quarter-century and would bring significant quantities of competitively priced gas to the utility’s customers.
Jerry Sleve, administrative vice president for the utility company, said “the combination of new local supplies and falling wholesale prices should result in much lower gas prices for our customers in the future.”
CNG’s new pipeline interconnects with a producer’s gathering line in Jackson Township, Pennsylvania.
“Given the Marcellus Shale prospects in our New York State service territory, CNG is hopeful of connecting more local production,” Sleve said, “More local production would likely put further downward pressure on gas prices, thereby helping not only core residential and commercial customers, but also providing a competitive advantage to local industries.”
German said that, “connecting local production is becoming a significant business opportunity for the company and we look forward to similar projects in the future.”
Wednesday, February 4, 2009
El Paso Natural Gas 2.5 Trillion Cubic Feet Equivalent
2.5 trillion cubic feet equivalent (Tcfe) proved
reserves, including the Company's proportionate interest
in Four Star Oil & Gas (Four Star)
-- 595 billion cubic feet equivalent (Bcfe) of reserve
additions prior to revisions
-- 192 percent reserve replacement prior to price-related
revisions
-- $2.87 per million cubic feet equivalent (Mcfe) domestic
reserve replacement costs prior to price-related revisions
-- Increased risked resource potential (which is in addition
to proved reserves) to 3.5 Tcfe
Note: Reserve additions include extensions, discoveries and purchases of reserves in place
El Paso Corporation (NYSE: EP) reported today that its proved natural gas and oil reserves at December 31, 2008 totaled 2.5 Tcfe, including 222 Bcfe related to its 48.8 percent interest in Four Star.
"El Paso had a very good year in terms of reserve additions, percentage of reserves replaced and domestic reserve replacement costs, excluding the effects of significant price-related revisions at year-end," said Doug Foshee, president and chief executive officer of El Paso Corporation. "Extensions and discoveries were up 69 percent over 2007 results, which demonstrate significant improvement in our E&P business. And the $2.87 per Mcfe domestic reserve replacement costs, excluding price-related revisions, is our best performance since I joined El Paso in 2003. While a sharp drop in commodity prices had a significant impact on year-end reserves, it is important to note that the year-end reserve calculation assumed very little reduction in service costs, which have fallen since year end and continue to decline. If we had calculated our year-end reserves assuming a Henry Hub natural gas price of $7.00 per MMBtu, $70.00 per barrel WTI pricing and assuming no further reduction in service costs, El Paso's reserves, including our interest in Four Star, would have been approximately 3.0 Tcfe."
Below is a reconciliation of consolidated proved reserves from December 31, 2007 to December 31, 2008, and a summary of El Paso's proportionate interest in Four Star proved reserves at December 31, 2008.
Consolidated Proved Reserves (Bcfe)*
------------------------------------
Proved Reserves at Dec. 31, 2007 2,853
Production (272)
Sales of Reserves in Place (303)
Extensions and Discoveries** 577
Purchases of Reserves in Place 18
Revisions Due to Price (476)
Revisions Other than Price (72)
Proved Reserves at Dec. 31, 2008 2,325
El Paso's Interest in Four Star Proved Reserves (Bcfe)
-----------------------------------------------------
Four Star at December 31, 2008 222
* Year end reserve estimates are based on $5.71 per MMBtu natural gas
(Henry Hub) and $44.60 per barrel (WTI) oil prices
** 128 Bcfe of reserve extensions and discoveries related to our Altamont
oil properties were based upon a $70 per barrel (WTI) oil prices, but were
ultimately eliminated due to price-related revisions at year end.
Approximately 74 percent of the December 31, 2008, proved reserves are proved developed, and 92 percent are natural gas. Approximately 85 percent of price-related revisions are attributable to the decline in oil and NGL prices. Of the price-related revisions, approximately 300 Bcfe were domestic, the largest portion of which was related to the company's Altamont oil properties. In addition, El Paso did not book any reserves from the Camarupim (Bia) project in Brazil due to the sharp drop in oil prices.
El Paso E&P's oil and gas 2008 capital expenditures were approximately $1.7 billion, which includes approximately $50 million for acquisitions of producing properties and approximately $200 million for international expenditures.
El Paso Corporation expects to take a fourth quarter after-tax full-cost ceiling test charge of $1.9 billion and a $0.1 billion impairment of its investment in Four Star. Approximately $1.4 billion of the full-cost ceiling test charge is attributable to the domestic full-cost pool and $0.5 billion to the Brazilian full-cost pool. The company uses the full-cost method of accounting for its oil and natural gas properties. The carrying value of these assets, net of related deferred income taxes, is evaluated on a quarterly basis and is limited to the present value of estimated net revenues of proved reserves using a 10-percent discount rate based on prices and costs at the end of the quarter plus the cost of unevaluated oil and natural gas properties (i.e. a cost center ceiling). A ceiling test charge occurs when the carrying value of the natural gas and oil assets exceeds the cost center ceiling.
El Paso has derivative positions that are intended to manage the price risk of its natural gas and oil production for 2009 and beyond. They are recorded on a mark-to-market basis and therefore were not included in the ceiling test calculation. These positions had a net asset value of approximately $700 million at December 31, 2008.
The ceiling test and impairment charges are non-cash items that do not impact any of the covenants on the debt obligations of El Paso Corporation or its subsidiaries. Based on current reserves and the expected fourth quarter 2008 ceiling test charge, the company estimates its first quarter 2009 per-unit DD&A rate will decline by approximately $0.90 per Mcfe from the rate used in the fourth quarter of 2008 to approximately $2.30 per Mcfe.
27 Percent Increase in Non-Proved Resources
El Paso also reported today that at December 31, 2008, it had an estimated 3.5 Tcfe of net risked or 6.6 Tcfe of net unrisked non-proved resource potential in addition to its 2.5 Tcfe of proved natural gas and oil reserves. The company's risked non-proved resource potential rose 0.7 Tcfe, or 27 percent, from 2007 levels. The majority of the increase was primarily due to the addition of new opportunities in the Haynesville Shale, infill opportunities in the Altamont Field and the Raton Basin coal bed methane program. Non-proved resources include the company's proportionate share of Four Star.
Foshee added, "One of our key successes in 2008 was the expansion of our future drilling inventory. The 2009 E&P capital program will optimize our current investment opportunities while preserving the drilling inventory that we have worked hard to develop, most of which is operated by El Paso and held by production."
A breakout of non-proved resources (risked/unrisked) is as follows:
Unconventional - 1,080/1,560 Bcfe - Unconventional resources primarily consist of the company's coal bed operations in the Raton, Black Warrior, and Arkoma Basins and its holdings in the New Albany and Haynesville shale plays.
Conventional, low-risk (probability of geologic success greater than or equal to 40 percent) - 1,770/2,300 Bcfe - This consists of conventional resources in the Rockies, south Texas, and Brazil development programs. It also includes tight-sand drilling in the ArkLaTex area.
Conventional, higher-risk (probability of geologic success less than 40 percent) - 700/2,785 Bcfe - This includes higher-risk exploration in the Gulf of Mexico, Texas Gulf Coast, and undrilled international exploration prospects in Brazil and Egypt.
Click here to view a chart showing the change in year end reserves, including the Company's proportionate interest in Four Star.
El Paso Corporation provides natural gas and related energy products in a safe, efficient, and dependable manner. The company owns North America's largest interstate natural gas pipeline system and one of North America's largest independent natural gas producers. For more information, visit www.elpaso.com.
Cautionary Note to U.S. Investors
Note that the SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We have used certain terms in this news release, such as risked and unrisked non-proved resource potential, that the SEC's guidelines strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under the assumed economic conditions. Risked and unrisked non-proved resource potential are estimates of potential reserves that are made using accepted geological and engineering analytical techniques, but which are estimated with reduced levels of certainty than for proved reserves. Unrisked resource potential is less certain than those for risked resource potential. Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our website at http://www.elpaso.com, including the inherent uncertainties in estimating quantities of proved reserves and non-proved resource potential.
CAUTIONARY STATEMENT
This release includes certain forward-looking statements and projections. The company has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors could cause actual results to differ materially from the projections, anticipated results or other expectations expressed in this release, including, without limitation, changes in unaudited and/or unreviewed financial information; the uncertainty of estimating proved reserves and non-proved potential, the future level of service costs, the availability and cost of financing to fund our future exploration and production operations; the effects of any changes in accounting rules and guidance; our ability to meet production volume targets in our Exploration and Production segment; changes in commodity prices and basis differentials for oil, natural gas, and power, including the impact upon our hedge positions and our full-cost ceiling test in the future; general economic and weather conditions in geographic regions or markets served by the company and its affiliates, or where operations of the company and its affiliates are located, including the risk of a global recession and negative impact on natural gas demand; political and currency risks associated with international operations of the company and its affiliates; competition; and other factors described in the company's (and its affiliates') Securities and Exchange Commission filings. While the company makes these statements and projections in good faith, neither the company nor its management can guarantee that anticipated future results will be achieved. Reference must be made to those filings for additional important factors that may affect actual results. The company assumes no obligation to publicly update or revise any forward-looking statements made herein or any other forward-looking statements made by the company, whether as a result of new information, future events, or otherwise.
Certain of the production information in this press release include the production attributable to El Paso's 49 percent interest in Four Star Oil & Gas Company ("Four Star"). El Paso's Supplemental Oil and Gas disclosures, which are included in its Annual Report on Form 10-K, reflect its proportionate share of the proved reserves of Four Star separate from its consolidated proved reserves. In addition, the proved reserves attributable to its proportionate share of Four Star represent estimates prepared by El Paso and not those of Four Star. The reserve replacement ratio and reserve replacement costs are two metrics we use to measure our ability to establish a long-term trend of adding reserves at a reasonable cost in our core asset areas. In this press release, we have excluded price-related revisions from the calculations of these metrics. These revisions are included in the calculations of these metrics as presented in company's Annual Report on Form 10-K. See the company's Annual Report on Form 10-K for further discussions of these metrics.
Contacts:
Investor-Media Relations
Bruce L. Connery
Vice President
Office: (713) 420-5855
Media Relations
Bill Baerg
Manager
Office: (713) 420-2906
reserves, including the Company's proportionate interest
in Four Star Oil & Gas (Four Star)
-- 595 billion cubic feet equivalent (Bcfe) of reserve
additions prior to revisions
-- 192 percent reserve replacement prior to price-related
revisions
-- $2.87 per million cubic feet equivalent (Mcfe) domestic
reserve replacement costs prior to price-related revisions
-- Increased risked resource potential (which is in addition
to proved reserves) to 3.5 Tcfe
Note: Reserve additions include extensions, discoveries and purchases of reserves in place
El Paso Corporation (NYSE: EP) reported today that its proved natural gas and oil reserves at December 31, 2008 totaled 2.5 Tcfe, including 222 Bcfe related to its 48.8 percent interest in Four Star.
"El Paso had a very good year in terms of reserve additions, percentage of reserves replaced and domestic reserve replacement costs, excluding the effects of significant price-related revisions at year-end," said Doug Foshee, president and chief executive officer of El Paso Corporation. "Extensions and discoveries were up 69 percent over 2007 results, which demonstrate significant improvement in our E&P business. And the $2.87 per Mcfe domestic reserve replacement costs, excluding price-related revisions, is our best performance since I joined El Paso in 2003. While a sharp drop in commodity prices had a significant impact on year-end reserves, it is important to note that the year-end reserve calculation assumed very little reduction in service costs, which have fallen since year end and continue to decline. If we had calculated our year-end reserves assuming a Henry Hub natural gas price of $7.00 per MMBtu, $70.00 per barrel WTI pricing and assuming no further reduction in service costs, El Paso's reserves, including our interest in Four Star, would have been approximately 3.0 Tcfe."
Below is a reconciliation of consolidated proved reserves from December 31, 2007 to December 31, 2008, and a summary of El Paso's proportionate interest in Four Star proved reserves at December 31, 2008.
Consolidated Proved Reserves (Bcfe)*
------------------------------------
Proved Reserves at Dec. 31, 2007 2,853
Production (272)
Sales of Reserves in Place (303)
Extensions and Discoveries** 577
Purchases of Reserves in Place 18
Revisions Due to Price (476)
Revisions Other than Price (72)
Proved Reserves at Dec. 31, 2008 2,325
El Paso's Interest in Four Star Proved Reserves (Bcfe)
-----------------------------------------------------
Four Star at December 31, 2008 222
* Year end reserve estimates are based on $5.71 per MMBtu natural gas
(Henry Hub) and $44.60 per barrel (WTI) oil prices
** 128 Bcfe of reserve extensions and discoveries related to our Altamont
oil properties were based upon a $70 per barrel (WTI) oil prices, but were
ultimately eliminated due to price-related revisions at year end.
Approximately 74 percent of the December 31, 2008, proved reserves are proved developed, and 92 percent are natural gas. Approximately 85 percent of price-related revisions are attributable to the decline in oil and NGL prices. Of the price-related revisions, approximately 300 Bcfe were domestic, the largest portion of which was related to the company's Altamont oil properties. In addition, El Paso did not book any reserves from the Camarupim (Bia) project in Brazil due to the sharp drop in oil prices.
El Paso E&P's oil and gas 2008 capital expenditures were approximately $1.7 billion, which includes approximately $50 million for acquisitions of producing properties and approximately $200 million for international expenditures.
El Paso Corporation expects to take a fourth quarter after-tax full-cost ceiling test charge of $1.9 billion and a $0.1 billion impairment of its investment in Four Star. Approximately $1.4 billion of the full-cost ceiling test charge is attributable to the domestic full-cost pool and $0.5 billion to the Brazilian full-cost pool. The company uses the full-cost method of accounting for its oil and natural gas properties. The carrying value of these assets, net of related deferred income taxes, is evaluated on a quarterly basis and is limited to the present value of estimated net revenues of proved reserves using a 10-percent discount rate based on prices and costs at the end of the quarter plus the cost of unevaluated oil and natural gas properties (i.e. a cost center ceiling). A ceiling test charge occurs when the carrying value of the natural gas and oil assets exceeds the cost center ceiling.
El Paso has derivative positions that are intended to manage the price risk of its natural gas and oil production for 2009 and beyond. They are recorded on a mark-to-market basis and therefore were not included in the ceiling test calculation. These positions had a net asset value of approximately $700 million at December 31, 2008.
The ceiling test and impairment charges are non-cash items that do not impact any of the covenants on the debt obligations of El Paso Corporation or its subsidiaries. Based on current reserves and the expected fourth quarter 2008 ceiling test charge, the company estimates its first quarter 2009 per-unit DD&A rate will decline by approximately $0.90 per Mcfe from the rate used in the fourth quarter of 2008 to approximately $2.30 per Mcfe.
27 Percent Increase in Non-Proved Resources
El Paso also reported today that at December 31, 2008, it had an estimated 3.5 Tcfe of net risked or 6.6 Tcfe of net unrisked non-proved resource potential in addition to its 2.5 Tcfe of proved natural gas and oil reserves. The company's risked non-proved resource potential rose 0.7 Tcfe, or 27 percent, from 2007 levels. The majority of the increase was primarily due to the addition of new opportunities in the Haynesville Shale, infill opportunities in the Altamont Field and the Raton Basin coal bed methane program. Non-proved resources include the company's proportionate share of Four Star.
Foshee added, "One of our key successes in 2008 was the expansion of our future drilling inventory. The 2009 E&P capital program will optimize our current investment opportunities while preserving the drilling inventory that we have worked hard to develop, most of which is operated by El Paso and held by production."
A breakout of non-proved resources (risked/unrisked) is as follows:
Unconventional - 1,080/1,560 Bcfe - Unconventional resources primarily consist of the company's coal bed operations in the Raton, Black Warrior, and Arkoma Basins and its holdings in the New Albany and Haynesville shale plays.
Conventional, low-risk (probability of geologic success greater than or equal to 40 percent) - 1,770/2,300 Bcfe - This consists of conventional resources in the Rockies, south Texas, and Brazil development programs. It also includes tight-sand drilling in the ArkLaTex area.
Conventional, higher-risk (probability of geologic success less than 40 percent) - 700/2,785 Bcfe - This includes higher-risk exploration in the Gulf of Mexico, Texas Gulf Coast, and undrilled international exploration prospects in Brazil and Egypt.
Click here to view a chart showing the change in year end reserves, including the Company's proportionate interest in Four Star.
El Paso Corporation provides natural gas and related energy products in a safe, efficient, and dependable manner. The company owns North America's largest interstate natural gas pipeline system and one of North America's largest independent natural gas producers. For more information, visit www.elpaso.com.
Cautionary Note to U.S. Investors
Note that the SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We have used certain terms in this news release, such as risked and unrisked non-proved resource potential, that the SEC's guidelines strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under the assumed economic conditions. Risked and unrisked non-proved resource potential are estimates of potential reserves that are made using accepted geological and engineering analytical techniques, but which are estimated with reduced levels of certainty than for proved reserves. Unrisked resource potential is less certain than those for risked resource potential. Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our website at http://www.elpaso.com, including the inherent uncertainties in estimating quantities of proved reserves and non-proved resource potential.
CAUTIONARY STATEMENT
This release includes certain forward-looking statements and projections. The company has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors could cause actual results to differ materially from the projections, anticipated results or other expectations expressed in this release, including, without limitation, changes in unaudited and/or unreviewed financial information; the uncertainty of estimating proved reserves and non-proved potential, the future level of service costs, the availability and cost of financing to fund our future exploration and production operations; the effects of any changes in accounting rules and guidance; our ability to meet production volume targets in our Exploration and Production segment; changes in commodity prices and basis differentials for oil, natural gas, and power, including the impact upon our hedge positions and our full-cost ceiling test in the future; general economic and weather conditions in geographic regions or markets served by the company and its affiliates, or where operations of the company and its affiliates are located, including the risk of a global recession and negative impact on natural gas demand; political and currency risks associated with international operations of the company and its affiliates; competition; and other factors described in the company's (and its affiliates') Securities and Exchange Commission filings. While the company makes these statements and projections in good faith, neither the company nor its management can guarantee that anticipated future results will be achieved. Reference must be made to those filings for additional important factors that may affect actual results. The company assumes no obligation to publicly update or revise any forward-looking statements made herein or any other forward-looking statements made by the company, whether as a result of new information, future events, or otherwise.
Certain of the production information in this press release include the production attributable to El Paso's 49 percent interest in Four Star Oil & Gas Company ("Four Star"). El Paso's Supplemental Oil and Gas disclosures, which are included in its Annual Report on Form 10-K, reflect its proportionate share of the proved reserves of Four Star separate from its consolidated proved reserves. In addition, the proved reserves attributable to its proportionate share of Four Star represent estimates prepared by El Paso and not those of Four Star. The reserve replacement ratio and reserve replacement costs are two metrics we use to measure our ability to establish a long-term trend of adding reserves at a reasonable cost in our core asset areas. In this press release, we have excluded price-related revisions from the calculations of these metrics. These revisions are included in the calculations of these metrics as presented in company's Annual Report on Form 10-K. See the company's Annual Report on Form 10-K for further discussions of these metrics.
Contacts:
Investor-Media Relations
Bruce L. Connery
Vice President
Office: (713) 420-5855
Media Relations
Bill Baerg
Manager
Office: (713) 420-2906
Tuesday, February 3, 2009
SME Goes Natural Gas
By KARL PUCKETT • Tribune Staff Writer • February 2, 2009
In uncertain regulatory climate has prompted a developer to scrap its plans for a $900 million coal-fired power plant east of Great Falls and turn instead to renewable energy to meet the needs of its 65,000 Montana customers.
Southern Montana Electric Generation and Transmission announced today that it will seek financing to construct a 120-megawatt combined cycle natural gas-fired facility, in addition to six megawatts of wind power.
For the past four years, SME has been working on the 250-megawatt coal-fired Highwood Generating Station, but it faced stiff opposition in the courts and a state environmental appeals board.
SME already was planning to build 6 megawatts of wind power at the coal-fired facility, but CEO Tim Gregori said additional wind megawatts could be added now depending on the outcome of financing.
Repeated appeals of the project made obtaining financing for Highwood Generating Station too uncertain for financing institutions, which prompted the change in direction, Gregori said.
“That cast a stigma not only on our plant, it cast a stigma on any energy development in the state,” he said.
The election of Democrat Barack Obama, who has pushed renewable energy and more emissions controls of greenhouse gases, was a factor in the decision because it created more uncertainty about the future of coal-fired power, Gregori said. But he said the state’s regula-tory system as the main factor in the about-face.
The system was used by opponents to repeatedly appeal the project, Gregori said. But the new plans are another example of how the developer has listened to the public’s concerns and responded, Gregori said.
Bozeman-based Earthjustice attorney Abigail Dillen, which represented opponents in the courts and before the state Board of Environmental Review, said she looked forward to working with SME in its investment in renewable energy.
“We are thrilled they’ve decided to move away from coal,” Dillen said.
Anne Hedges of the Montana Environmental Information Center, calling coal-fired power plants the leading emitter of climate changing pollution, said SME’s decision was an “enormous step forward.”
“We can no longer continue to ignore global warming,” she said.
She added that SME should still move the natural gas fired power plant and the wind generation to a new site, calling it an industrial facility in the middle of farmland.
If opponents oppose Highwood now even after the changes, they are “hypocrites,” Gregori said.
SME broke ground on the coal-fired facility this past fall. Gregori said much of the preparation work will fit well with construction of the natural gas facility.
SME is speaking with the same “entities” about financing as it was when the project involved a coal-fire power plant, Gregori said.
Highwood is proposed by four rural cooperatives and would serve 65,000 Montanans including some customers served by the utility arm for the city of Great Falls.
In uncertain regulatory climate has prompted a developer to scrap its plans for a $900 million coal-fired power plant east of Great Falls and turn instead to renewable energy to meet the needs of its 65,000 Montana customers.
Southern Montana Electric Generation and Transmission announced today that it will seek financing to construct a 120-megawatt combined cycle natural gas-fired facility, in addition to six megawatts of wind power.
For the past four years, SME has been working on the 250-megawatt coal-fired Highwood Generating Station, but it faced stiff opposition in the courts and a state environmental appeals board.
SME already was planning to build 6 megawatts of wind power at the coal-fired facility, but CEO Tim Gregori said additional wind megawatts could be added now depending on the outcome of financing.
Repeated appeals of the project made obtaining financing for Highwood Generating Station too uncertain for financing institutions, which prompted the change in direction, Gregori said.
“That cast a stigma not only on our plant, it cast a stigma on any energy development in the state,” he said.
The election of Democrat Barack Obama, who has pushed renewable energy and more emissions controls of greenhouse gases, was a factor in the decision because it created more uncertainty about the future of coal-fired power, Gregori said. But he said the state’s regula-tory system as the main factor in the about-face.
The system was used by opponents to repeatedly appeal the project, Gregori said. But the new plans are another example of how the developer has listened to the public’s concerns and responded, Gregori said.
Bozeman-based Earthjustice attorney Abigail Dillen, which represented opponents in the courts and before the state Board of Environmental Review, said she looked forward to working with SME in its investment in renewable energy.
“We are thrilled they’ve decided to move away from coal,” Dillen said.
Anne Hedges of the Montana Environmental Information Center, calling coal-fired power plants the leading emitter of climate changing pollution, said SME’s decision was an “enormous step forward.”
“We can no longer continue to ignore global warming,” she said.
She added that SME should still move the natural gas fired power plant and the wind generation to a new site, calling it an industrial facility in the middle of farmland.
If opponents oppose Highwood now even after the changes, they are “hypocrites,” Gregori said.
SME broke ground on the coal-fired facility this past fall. Gregori said much of the preparation work will fit well with construction of the natural gas facility.
SME is speaking with the same “entities” about financing as it was when the project involved a coal-fire power plant, Gregori said.
Highwood is proposed by four rural cooperatives and would serve 65,000 Montanans including some customers served by the utility arm for the city of Great Falls.
Monday, February 2, 2009
Chinese Natural Gas Output Increased in 2008
Chinese natural gas output up by 12.3% in 2008 - steelguru.com
Xinhua quoted an industry association said China's production of natural gas rose 12.3%YoY to 76.1 billion cubic meters in 2008 as the government promoted cleaner energy.
The China Petroleum and Chemical Industry Association said the annual growth rate was down from 23.1% in 2007.
According to statistics from BP China consumed 67.3 billion cubic meters of gas in 2007, an annual increase of 19.9%. This compared to 55.6 billion cubic meters in 2006 up by 21.6% from the previous year. Consumption figures for 2008 are unavailable.
China's production and consumption of natural gas have been rising steadily since the government set a target of raising the proportion of natural gas in total energy consumption to 5.3% by 2010 from 2.8% in 2005. The plan was aimed to shift away from a heavy reliance on coal, which accounts for about 70% of total energy consumption.
The CPCIA said the expansion of the natural gas infrastructure, including pipelines, reflected the rapid increases in output and consumption.
In 2008, China launched construction of the second east-west gas pipeline and the connection of Central Asia gas pipeline. The new pipelines are scheduled to become operational by the end of 2009 and will have an annual capacity of 30 billion cubic meters. They will mainly carry natural gas from Central Asia to the Yangtze and Pearl River deltas, the country's two most developed regions.
Construction of more liquefied natural gas terminals were also launched last year, while LNG purchase agreements were signed between state oil producers and foreign LNG sellers, including Shell, Total and Qatar Gas, despite higher natural gas prices driven by record oil price hikes in 2008. Those agreements would add possible annual imports of more than 8 million tons.
Xinhua quoted an industry association said China's production of natural gas rose 12.3%YoY to 76.1 billion cubic meters in 2008 as the government promoted cleaner energy.
The China Petroleum and Chemical Industry Association said the annual growth rate was down from 23.1% in 2007.
According to statistics from BP China consumed 67.3 billion cubic meters of gas in 2007, an annual increase of 19.9%. This compared to 55.6 billion cubic meters in 2006 up by 21.6% from the previous year. Consumption figures for 2008 are unavailable.
China's production and consumption of natural gas have been rising steadily since the government set a target of raising the proportion of natural gas in total energy consumption to 5.3% by 2010 from 2.8% in 2005. The plan was aimed to shift away from a heavy reliance on coal, which accounts for about 70% of total energy consumption.
The CPCIA said the expansion of the natural gas infrastructure, including pipelines, reflected the rapid increases in output and consumption.
In 2008, China launched construction of the second east-west gas pipeline and the connection of Central Asia gas pipeline. The new pipelines are scheduled to become operational by the end of 2009 and will have an annual capacity of 30 billion cubic meters. They will mainly carry natural gas from Central Asia to the Yangtze and Pearl River deltas, the country's two most developed regions.
Construction of more liquefied natural gas terminals were also launched last year, while LNG purchase agreements were signed between state oil producers and foreign LNG sellers, including Shell, Total and Qatar Gas, despite higher natural gas prices driven by record oil price hikes in 2008. Those agreements would add possible annual imports of more than 8 million tons.
Sunday, February 1, 2009
Natural Gas Price Pressured by LNG
By TOM FOWLER Copyright 2009 Houston Chronicle
Jan. 31, 2009, 1:47AMAs many as seven massive natural gas export terminals are expected to start up overseas this year, expanding worldwide capacity by 20 percent and flooding markets with new supplies of the key power plant and heating fuel. Dozens of new tankers capable of carrying natural gas in a liquefied form are slated to hit the seas.
Just as these new supplies come on line, worldwide demand is expected to drop as the global recession deepens.
Operators of these new facilities are unlikely to cut back production, however, so shipments of liquefied natural gas will most likely head to the deepest markets with the greatest amount of natural gas storage capacity — the United States.
‘Counterintuitive’
“It’s completely counterintuitive,” said Murray Douglas, a global LNG analyst with Wood Mackenzie in Houston, who is predicting U.S. LNG imports will grow 30 percent to 456 billion cubic feet this year and to more than 1.1 trillion cubic feet by 2013.
“We don’t believe Asia and Europe will be in a position to absorb this new production, and the U.S. is the only market that can take it, that has a large amount of storage.”
The wave of imports might even be strong enough to challenge growing domestic natural gas production from various shale formations, including the Barnett Shale near Fort Worth and Fayetteville Shale in Arkansas.
“This can put pressure on U.S. gas prices and could delay the full development of some of the new shale pro-jects,” Douglas said.
Other analysts, including Houston-based Waterborne Energy and Raleigh, N.C.-based Pan Eurasia Enterprises, agree that an American gas import surge may be coming.
Even the Department of Energy updated its LNG import predictions for 2009 recently to include the possibility of such a surge.
Big energy chunk
Natural gas accounts for 23 percent of total energy consumed in the U.S., according to the Department of Energy, much of it used to fuel power plants.
Twelve percent of the gas comes from foreign suppliers, most of it through pipelines from Canada, and about 3 percent comes from overseas aboard LNG tankers.
Changing to liquid
Natural gas turns into liquid at minus 260 degrees Fahrenheit. In that condensed form, it can be transported in specially designed oceangoing tankers. When the tankers reach a gasification terminal, the liquid is heated back into gas for transport by pipeline.
2007 was a record year for LNG imports into the U.S., with some 770 billion cubic feet arriving through five terminals.
Three terminals came on line in 2008, including Houston-based Cheniere Energy’s terminal on the Louisiana side of the Sabine Pass south of Port Arthur and Freeport LNG’s terminal on Quintana Island south of Houston. The third, owned by The Woodlands-based Excelerate Energy, is near Boston.
Timing not ideal
The timing was bad. U.S. imports slowed as tankers were drawn both to Europe — where prices spiked recently because of ongoing supply disputes with Russia — and Asia, where economic growth and the shutdown of a large nuclear power plant in Japan because of earthquake damage led to greater demand for natural gas to run other power plants.
More of the same was expected for this year. Some equity research firms even stopped tracking LNG terminal operators.
Asia-Pacific region
But the coming wave of new export terminals, where the gas is liquefied and loaded on tankers, is centered largely in the Asia-Pacific region, said Steve Johnson, president of Waterborne Energy. That means those markets will be well-served, leaving more tankers available for Atlantic markets — with the U.S. being the deepest and most liquid.
One might expect the new LNG exporters to delay opening, or at least cut back their output given the lower demand.
But the gas liquefaction projects have been planned over many years and cost their host governments many billions of dollars, Johnson said.
“Shutting it down is the last thing they will do,” Johnson said.
Competitive price
LNG can be competitive priced as low as $3 per million British thermal units, said Zach Allen, head of Pan EurAsian Enterprises, a management advisory firm that follows LNG markets. That’s a price the U.S. hasn’t seen since 2002.
While LNG generally is sold in contracts between importers and exporters, its price is influenced by the price of natural gas traded on the New York Mercantile exchange, which closed Friday at $4.42 per million Btu.
“Some cash is better than none, especially for producers who rely heavily on that cash for social and other programs that would be politically explosive to cut off or cut back,” Allen said.
Some of Qatar’s natural gas fields produce other valuable liquids that are stripped out and sold at prices that essentially cover all production costs before the gas even makes it to market, Douglas said.
“They are essentially producing the gas for free,” Douglas said.
The cost of getting the LNG from its foreign origin to other markets can be relatively low, Johnson said.
The 43-day round trip from the huge export terminal in Qatar to the Lake Charles, La., LNG terminal costs $2.09 per million British thermal units.
From Egypt to Lake Charles takes 30 days and $1.29 per million Btu.
tom.fowler@chron.com
Jan. 31, 2009, 1:47AMAs many as seven massive natural gas export terminals are expected to start up overseas this year, expanding worldwide capacity by 20 percent and flooding markets with new supplies of the key power plant and heating fuel. Dozens of new tankers capable of carrying natural gas in a liquefied form are slated to hit the seas.
Just as these new supplies come on line, worldwide demand is expected to drop as the global recession deepens.
Operators of these new facilities are unlikely to cut back production, however, so shipments of liquefied natural gas will most likely head to the deepest markets with the greatest amount of natural gas storage capacity — the United States.
‘Counterintuitive’
“It’s completely counterintuitive,” said Murray Douglas, a global LNG analyst with Wood Mackenzie in Houston, who is predicting U.S. LNG imports will grow 30 percent to 456 billion cubic feet this year and to more than 1.1 trillion cubic feet by 2013.
“We don’t believe Asia and Europe will be in a position to absorb this new production, and the U.S. is the only market that can take it, that has a large amount of storage.”
The wave of imports might even be strong enough to challenge growing domestic natural gas production from various shale formations, including the Barnett Shale near Fort Worth and Fayetteville Shale in Arkansas.
“This can put pressure on U.S. gas prices and could delay the full development of some of the new shale pro-jects,” Douglas said.
Other analysts, including Houston-based Waterborne Energy and Raleigh, N.C.-based Pan Eurasia Enterprises, agree that an American gas import surge may be coming.
Even the Department of Energy updated its LNG import predictions for 2009 recently to include the possibility of such a surge.
Big energy chunk
Natural gas accounts for 23 percent of total energy consumed in the U.S., according to the Department of Energy, much of it used to fuel power plants.
Twelve percent of the gas comes from foreign suppliers, most of it through pipelines from Canada, and about 3 percent comes from overseas aboard LNG tankers.
Changing to liquid
Natural gas turns into liquid at minus 260 degrees Fahrenheit. In that condensed form, it can be transported in specially designed oceangoing tankers. When the tankers reach a gasification terminal, the liquid is heated back into gas for transport by pipeline.
2007 was a record year for LNG imports into the U.S., with some 770 billion cubic feet arriving through five terminals.
Three terminals came on line in 2008, including Houston-based Cheniere Energy’s terminal on the Louisiana side of the Sabine Pass south of Port Arthur and Freeport LNG’s terminal on Quintana Island south of Houston. The third, owned by The Woodlands-based Excelerate Energy, is near Boston.
Timing not ideal
The timing was bad. U.S. imports slowed as tankers were drawn both to Europe — where prices spiked recently because of ongoing supply disputes with Russia — and Asia, where economic growth and the shutdown of a large nuclear power plant in Japan because of earthquake damage led to greater demand for natural gas to run other power plants.
More of the same was expected for this year. Some equity research firms even stopped tracking LNG terminal operators.
Asia-Pacific region
But the coming wave of new export terminals, where the gas is liquefied and loaded on tankers, is centered largely in the Asia-Pacific region, said Steve Johnson, president of Waterborne Energy. That means those markets will be well-served, leaving more tankers available for Atlantic markets — with the U.S. being the deepest and most liquid.
One might expect the new LNG exporters to delay opening, or at least cut back their output given the lower demand.
But the gas liquefaction projects have been planned over many years and cost their host governments many billions of dollars, Johnson said.
“Shutting it down is the last thing they will do,” Johnson said.
Competitive price
LNG can be competitive priced as low as $3 per million British thermal units, said Zach Allen, head of Pan EurAsian Enterprises, a management advisory firm that follows LNG markets. That’s a price the U.S. hasn’t seen since 2002.
While LNG generally is sold in contracts between importers and exporters, its price is influenced by the price of natural gas traded on the New York Mercantile exchange, which closed Friday at $4.42 per million Btu.
“Some cash is better than none, especially for producers who rely heavily on that cash for social and other programs that would be politically explosive to cut off or cut back,” Allen said.
Some of Qatar’s natural gas fields produce other valuable liquids that are stripped out and sold at prices that essentially cover all production costs before the gas even makes it to market, Douglas said.
“They are essentially producing the gas for free,” Douglas said.
The cost of getting the LNG from its foreign origin to other markets can be relatively low, Johnson said.
The 43-day round trip from the huge export terminal in Qatar to the Lake Charles, La., LNG terminal costs $2.09 per million British thermal units.
From Egypt to Lake Charles takes 30 days and $1.29 per million Btu.
tom.fowler@chron.com
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