KIEV, Ukraine (AP) — Ukraine's gas company Naftogaz says it will pay up to $2 billion to settle its debt for Russian gas imports and avoid a threatened cutoff of natural gas deliveries.
Tuesday's announcement appears to mark an end to a bitter confrontation between Russia and Ukraine that threatened to disrupt supplies to Europe.
Naftogaz spokesman Valentyn Zemlyansky says the company will take loans from Ukraine's two biggest state-run banks to pay off the debt. Zemlyansky says the money will be transferred Tuesday.
Earlier Tuesday, Russia's natural gas company Gazprom said it would stop energy shipments to Ukraine and sharply raise the price for future deliveries if it didn't pay the debt by New Year's Eve.
THIS IS A BREAKING NEWS UPDATE. Check back soon for further information. AP's earlier story is below.
MOSCOW (AP) — Russia's natural gas company Gazprom will stop energy shipments to Ukraine and sharply raise the price for future deliveries if it doesn't pay a $2 billion debt by New Year's Eve, the company's chief executive warned Tuesday.
Ukraine faces a replay of the January 2006 crisis, when a cutoff of Russian gas shipments resulted in a brief reduction of supplies in Europe. The state-run Gazprom supplies a quarter of the gas used by EU nations, and around 80 percent of it goes through Ukraine.
But this year could be worse. The financial crisis has hit Ukraine harder than most other European countries, and Kiev was recently forced to seek a $16.5 billion loan from the International Monetary Fund.
"The countdown has started," Gazprom CEO Alexei Miller said in a televised statement. "If Ukraine doesn't pay off the debt by Dec. 31, Gazprom will have no grounds to continue shipping gas to Ukraine."
Gazprom spokesman Sergei Kupriyanov said Miller was continuing to negotiate with Oleh Dubina, the head of Ukraine's gas company Naftogaz, but his comments reflected the tense atmosphere of the talks.
"My boss is now sitting with Dubina in both the direct and figurative sense of the word," Kupriyanov said, referring to the fact that Dubina's name can mean "blockhead" in Russian.
Gazprom's spokesman said the company would "do its best" to ensure supplies to Europe, adding that Russia has a valid transit contract with Ukraine that is separate from the supply deal.
He said Russia and Ukraine are discussing different options for the debt settlement, including the possibility of Gazprom paying Ukraine in advance for transit, with the money to go toward repaying the debt.
The Interfax news agency reported from Kiev that the Ukrainian government has approved a transit fees-for-debt swap, citing an unnamed participant. Naftogaz spokesman Valentyn Zemlyansky denied the report, but said Ukraine still hopes to reach an agreement before Thursday.
Gazprom is demanding that Ukraine pay $418 per 1,000 cubic meters for future deliveries, roughly what Russia charges other European consumers. That would more than double the current price of $179.50.
Ukraine insists the price should be significantly lower, but Kupriyanov said Ukraine had to pay off its debt first before it can negotiate a lower price.
While Gazprom's European customers now pay the higher price, the cost of gas is expected to fall sharply in coming months as a result of the steep drop in the price of oil.
For months, Russia and Ukraine have been locked in a dispute over past and future natural gas shipments from Gazprom, which has seen the value of its stock slip by almost 75 percent since the beginning of 2008.
Gazprom's net earnings climbed to $10.2 billion in an unaudited 2008 first-half earnings report released Tuesday. The same report showed the company's debt has dropped from $84.5 billion at the end of 2007 to $69 billion on June 30. In recent years, the state gas company has spent billions to acquire oil and other assets on behalf of the Kremlin.
Analysts said Tuesday that Ukraine would be hard pressed to pay the $418 price for future gas deliveries.
"This year is especially tough because the financial crisis has hit Ukraine hard," said Ron Smith, chief strategist at Alfa Bank. "I'm sure Gazprom's suggesting the debts can be exchanged for Gazprom ownership of the Ukrainian transit pipes, which, of course, Ukraine will not do."
Gas analysts noted that Gazprom reviews gas prices in its European contract every quarter to reflect changes in energy prices. Valery Nesterov, a gas analyst with Troika Dialog, predicted that Ukraine may agree to the $418 price in the short run, expecting the price to decline in the future.
"It would be hard for Ukraine to come to terms with $300 to $400, but in the next three or five years we are not going to see this level of prices," Nesterov said.
Associated Press Writer Maria Danilova in Kiev contributed to this report.
Wednesday, December 31, 2008
Tuesday, December 30, 2008
Shell Buys Natural Gas Virginia Company
Baltimore Business Journal
Shell Energy North America(US) LP is acquiring the mid-Atlantic natural gas marketing company Enspire Energy LLC.
Financial details of the deal, which is expected to close in the first quarter of 2009, were not disclosed.
Virginia-based Enspire, which has offices in Norfolk and Annapolis, supplies natural gas to customers in the mid-Atlantic states — specializing in "mid-sized commercial and industrial accounts," according to its president, Jim Lukas, who founded the company in 2005 after two decades with other energy businesses.
"Enspire has been a tremendous success story in the region," Lukas said in an interview Monday afternoon, noting its growth to $200 million in revenue for the 12-month period that ended Nov. 1.
Lukas said his company purchases natural gas "at the wellhead," arranges for its transmission through common pipelines and delivery at customers' meters, and offers "a range of pricing options."
Among Enspire's customers are the U.S. Capitol, steel plants and hospitals, said Lukas, reached through his Annapolis office.
The company has eight employees, including Lukas, who said he anticipated a "growth mode" as a result of the acquisition by Shell — although personnel needs will have to be coordinated with the new owner. Among the possible changes is expansion into the power arena by offering electricity, he said.
"I will be an employee of Shell," he said. "It's a great organization. They've basically been our credit supplier for the last three years."
Mark Quartermain, president of Houston-based Shell Energy North America, a subsidiary of Royal Dutch Shell plc, said the acquisition would boost the range of services offered by Shell Energy in the region currently served by Enspire.
Lukas, in Friday's announcement of the deal, said, "Enspire's regional expertise combined with Shell's assets and financial strength will help us provide an increased array of products while maintaining the superior service to which our customers are accustomed.”
Shell Energy North America(US) LP is acquiring the mid-Atlantic natural gas marketing company Enspire Energy LLC.
Financial details of the deal, which is expected to close in the first quarter of 2009, were not disclosed.
Virginia-based Enspire, which has offices in Norfolk and Annapolis, supplies natural gas to customers in the mid-Atlantic states — specializing in "mid-sized commercial and industrial accounts," according to its president, Jim Lukas, who founded the company in 2005 after two decades with other energy businesses.
"Enspire has been a tremendous success story in the region," Lukas said in an interview Monday afternoon, noting its growth to $200 million in revenue for the 12-month period that ended Nov. 1.
Lukas said his company purchases natural gas "at the wellhead," arranges for its transmission through common pipelines and delivery at customers' meters, and offers "a range of pricing options."
Among Enspire's customers are the U.S. Capitol, steel plants and hospitals, said Lukas, reached through his Annapolis office.
The company has eight employees, including Lukas, who said he anticipated a "growth mode" as a result of the acquisition by Shell — although personnel needs will have to be coordinated with the new owner. Among the possible changes is expansion into the power arena by offering electricity, he said.
"I will be an employee of Shell," he said. "It's a great organization. They've basically been our credit supplier for the last three years."
Mark Quartermain, president of Houston-based Shell Energy North America, a subsidiary of Royal Dutch Shell plc, said the acquisition would boost the range of services offered by Shell Energy in the region currently served by Enspire.
Lukas, in Friday's announcement of the deal, said, "Enspire's regional expertise combined with Shell's assets and financial strength will help us provide an increased array of products while maintaining the superior service to which our customers are accustomed.”
Monday, December 29, 2008
Bush Promoting California Natural Gas Drilling?
(12-28) 18:51 PST -- The federal government is taking steps that may open California's fabled coast to oil drilling in as soon as three years, an action that could place dozens of platforms off the Sonoma, Mendocino and Humboldt coasts along with the specter of spills, air pollution and increased ship traffic into San Francisco Bay.Millions of acres of oil deposits, mapped in the 1980s when then-Interior Secretary James Watt and Energy Secretary Donald Hodel pushed for California exploration, lie a few miles from the forested North Coast and near the mouth of the Russian River, as well as in Santa Monica Bay and off Malibu and La Jolla in Southern California.
"These are the targets," said Richard Charter, a lobbyist for the Defenders of Wildlife Action Fund who worked for three decades to win congressional bans on offshore drilling. "You couldn't design a better formula to create adverse impacts on California's coastal-dependent economy."
The bans that protected both of the nation's coasts beginning in 1981, from California to the Pacific Northwest to the Atlantic coast and the Straits of Florida, ended this year when Congress let the moratorium lapse.
President-elect Barack Obama hasn't said whether he would overturn President Bush's lifting last summer of the ban on drilling, as gas prices reached a historic high. Sen. Ken Salazar, D-Col., Obama's pick as interior secretary and head of the nation's ocean-drilling agency, hasn't said what he would do in coastal waters.
The Interior Department has moved to open some or all federal waters, which begin 3 miles from shore and are outside state control, for exploration as early as 2010. Rigs could go up in 2012.
National marine sanctuaries off San Francisco and Monterey Bays are off limits in California. Areas open to drilling extend from Bodega Bay north to the Oregon border and from Morro Bay south to the U.S.-Mexico border.
Drilling foes think the impacts of explosive blasts from seismic air guns that map rock formations, increased vessel traffic and oil spills are enough to persuade federal agencies to thwart petroleum explorers. California's treasured coast, with its migrating whales, millions of seabirds, sea otters, fish and crab feeding grounds, beaches and tidal waters, are at risk, Charter and other opponents say.
According to the Interior Department, coastal areas nationwide that were affected by the drilling ban contain 18 billion barrels of oil and 76 trillion cubic feet of natural gas in what the agency called yet-to-be-discovered fields. The estimates are conservative, and are based on seismic surveys in the late 1970s and early 1980s, before the moratorium went into effect.
10 billion barrels
The agency's last estimate puts about 10 billion barrels in California, enough to supply the nation for 17 months. That breaks down to 2.1 billion barrels from Point Arena in Mendocino County north to the Oregon border, 2.3 billion from Point Arena south to San Luis Obispo County and 5.6 billion from there south to Mexico.
"If you were allowed to go out and do new exploration, those numbers could go up or down. In most cases, you would expect them to go up," said Dave Smith, deputy communications officer of the Interior Department's Minerals Management Service, which oversees energy development in federal waters.
In California, any exploration and drilling would be close to shore, experts say. In contrast to the Gulf of Mexico, where drilling could occur in deep waters at 10,000 feet, California's holdings lie on its narrow, shallow continental shelf, the underwater edge of land where creatures died over millennia to produce the oil.
If the Interior Department decides to explore off California's coast, it could probably do so, some attorneys say. If a state objects to a lease plan, the president has the final say.
Once an area has been leased, the California Coastal Commission may review an oil company's plan to explore or extract resources to assess if it is consistent with the state's coastal management program. Conflicts can end up in court, said Alison Dettmer, the commission's deputy director.
Californians have generally opposed drilling since a platform blowout in 1969 splashed 3 million gallons of black, gooey crude oil on 35 miles of Santa Barbara beaches, killing otters and seabirds. The destruction of shoreline and wildlife sparked activism and led to the creation of the Coastal Commission.
But when gas prices peaked a few months ago, amid cries of "drill, baby, drill" at rallies for GOP presidential candidate John McCain and running mate Sarah Palin, 51 percent of Californians said they favored more offshore drilling, according to a survey by the Public Policy Institute of California.
In July, Interior Secretary Dirk Kempthorne jump-started the development of a new oil and natural gas leasing program and pushed up possible new coastal activity by two years.
The Interior Department is reviewing comments about which coastal areas to include in the next five-year leasing plan. Oil companies want all of the nation's coastal areas open and say they can produce from offshore in a way that protects the environment. Gov. Arnold Schwarzenegger, who opposes new offshore development, has offered comments, as have environmental groups.
Obama's energy plans
Obama's administration and Congress will have the final say over which regions, if any, would be put up for possible lease sales. In Congress earlier this year, Salazar, Obama's nominee for interior secretary, supported a bipartisan bill allowing exploration and production 50 miles out from the Atlantic southern coast with state approval. The bill died.
"We've been encouraged that the president-elect has chosen Sen. Salazar," said Dan Naatz, vice president for federal resources with the Independent Petroleum Association of America, a group with 5,000 members that drill 90 percent of the oil and natural gas wells in the United States. "He's from the West, and he understands federal land policy, which is really key."
During this year's presidential campaign, Obama was bombarded by questions about high gas prices and said new domestic drilling wouldn't do much to lower gasoline prices but could have a place in a comprehensive energy program.
After introducing his green team of environment and energy chiefs recently, Obama said the foundation of the nation's energy independence lay in the "power of wind and solar, in new crops and new technologies, in the innovation of our scientists and entrepreneurs and the dedication and skill of our workforce."
He spoke of moving "beyond our oil addiction," creating "a new, hybrid economy" and investing in "renewable energy that will give life to new businesses and industries."
Obama didn't mention oil drilling. When a reporter asked him if he would reinstate the moratorium, he said he wasn't happy that the moratorium was allowed to lapse in Congress without a broader thought to how the country was going to reduce dependence on fossil fuels.
He reiterated his campaign position that he was open to the idea of offshore drilling if it was part of a comprehensive package, adding that he would turn over the question to his team.
In the 1970s and 1980s, before the moratorium on offshore drilling fully took effect, the federal government produced a series of maps showing areas in California of prospective interest to the oil industry. Those maps offer clues to where oil companies would bid if they had the opportunity.
Last proposed lease
The last proposed lease sale in 1987, thwarted by the moratorium, would have opened 6.5 million acres off the North Coast. Off Mendocino and Humboldt counties, the tracts for sale lay from 3 to 27 miles offshore, and some of the 24 planned platforms, some of them 300 feet tall and each with dozens of wells, would have been visible from land.
Tourism and commercial fisheries would have been affected, according to an environmental review then, while as many as 240 new oil tanker trips from Fort Bragg and Eureka to the San Francisco Bay refineries were predicted under the full development scenario. The probability of one or more spills occurring would be 94 percent for accidents involving 1,000 barrels or more, according to documents.
Rep. Lois Capps, D-Santa Barbara, a member of the House Natural Resources Committee, recently said oil drilling will be part of a comprehensive energy policy focusing on renewable sources, but she would like to see drilling occur only on land and in the Gulf of Mexico where infrastructure is in place.
Capps well remembers the Santa Barbara spill almost 40 years ago.
"I was living in Goleta. I just had two children, and my husband was a young professor at UC Santa Barbara. It was a devastating experience," she said. "The birds and other animals got trapped in the oil. So many people waded out in boots just inch by inch trying to rescue our wildlife. It ruined our tourism for many years.
"I think about it all the time, especially last week when we had had a spill at the same platform. It was a small spill, 1,000 gallons, but it was a wake-up call."
E-mail Jane Kay at jkay@sfchronicle.com.
"These are the targets," said Richard Charter, a lobbyist for the Defenders of Wildlife Action Fund who worked for three decades to win congressional bans on offshore drilling. "You couldn't design a better formula to create adverse impacts on California's coastal-dependent economy."
The bans that protected both of the nation's coasts beginning in 1981, from California to the Pacific Northwest to the Atlantic coast and the Straits of Florida, ended this year when Congress let the moratorium lapse.
President-elect Barack Obama hasn't said whether he would overturn President Bush's lifting last summer of the ban on drilling, as gas prices reached a historic high. Sen. Ken Salazar, D-Col., Obama's pick as interior secretary and head of the nation's ocean-drilling agency, hasn't said what he would do in coastal waters.
The Interior Department has moved to open some or all federal waters, which begin 3 miles from shore and are outside state control, for exploration as early as 2010. Rigs could go up in 2012.
National marine sanctuaries off San Francisco and Monterey Bays are off limits in California. Areas open to drilling extend from Bodega Bay north to the Oregon border and from Morro Bay south to the U.S.-Mexico border.
Drilling foes think the impacts of explosive blasts from seismic air guns that map rock formations, increased vessel traffic and oil spills are enough to persuade federal agencies to thwart petroleum explorers. California's treasured coast, with its migrating whales, millions of seabirds, sea otters, fish and crab feeding grounds, beaches and tidal waters, are at risk, Charter and other opponents say.
According to the Interior Department, coastal areas nationwide that were affected by the drilling ban contain 18 billion barrels of oil and 76 trillion cubic feet of natural gas in what the agency called yet-to-be-discovered fields. The estimates are conservative, and are based on seismic surveys in the late 1970s and early 1980s, before the moratorium went into effect.
10 billion barrels
The agency's last estimate puts about 10 billion barrels in California, enough to supply the nation for 17 months. That breaks down to 2.1 billion barrels from Point Arena in Mendocino County north to the Oregon border, 2.3 billion from Point Arena south to San Luis Obispo County and 5.6 billion from there south to Mexico.
"If you were allowed to go out and do new exploration, those numbers could go up or down. In most cases, you would expect them to go up," said Dave Smith, deputy communications officer of the Interior Department's Minerals Management Service, which oversees energy development in federal waters.
In California, any exploration and drilling would be close to shore, experts say. In contrast to the Gulf of Mexico, where drilling could occur in deep waters at 10,000 feet, California's holdings lie on its narrow, shallow continental shelf, the underwater edge of land where creatures died over millennia to produce the oil.
If the Interior Department decides to explore off California's coast, it could probably do so, some attorneys say. If a state objects to a lease plan, the president has the final say.
Once an area has been leased, the California Coastal Commission may review an oil company's plan to explore or extract resources to assess if it is consistent with the state's coastal management program. Conflicts can end up in court, said Alison Dettmer, the commission's deputy director.
Californians have generally opposed drilling since a platform blowout in 1969 splashed 3 million gallons of black, gooey crude oil on 35 miles of Santa Barbara beaches, killing otters and seabirds. The destruction of shoreline and wildlife sparked activism and led to the creation of the Coastal Commission.
But when gas prices peaked a few months ago, amid cries of "drill, baby, drill" at rallies for GOP presidential candidate John McCain and running mate Sarah Palin, 51 percent of Californians said they favored more offshore drilling, according to a survey by the Public Policy Institute of California.
In July, Interior Secretary Dirk Kempthorne jump-started the development of a new oil and natural gas leasing program and pushed up possible new coastal activity by two years.
The Interior Department is reviewing comments about which coastal areas to include in the next five-year leasing plan. Oil companies want all of the nation's coastal areas open and say they can produce from offshore in a way that protects the environment. Gov. Arnold Schwarzenegger, who opposes new offshore development, has offered comments, as have environmental groups.
Obama's energy plans
Obama's administration and Congress will have the final say over which regions, if any, would be put up for possible lease sales. In Congress earlier this year, Salazar, Obama's nominee for interior secretary, supported a bipartisan bill allowing exploration and production 50 miles out from the Atlantic southern coast with state approval. The bill died.
"We've been encouraged that the president-elect has chosen Sen. Salazar," said Dan Naatz, vice president for federal resources with the Independent Petroleum Association of America, a group with 5,000 members that drill 90 percent of the oil and natural gas wells in the United States. "He's from the West, and he understands federal land policy, which is really key."
During this year's presidential campaign, Obama was bombarded by questions about high gas prices and said new domestic drilling wouldn't do much to lower gasoline prices but could have a place in a comprehensive energy program.
After introducing his green team of environment and energy chiefs recently, Obama said the foundation of the nation's energy independence lay in the "power of wind and solar, in new crops and new technologies, in the innovation of our scientists and entrepreneurs and the dedication and skill of our workforce."
He spoke of moving "beyond our oil addiction," creating "a new, hybrid economy" and investing in "renewable energy that will give life to new businesses and industries."
Obama didn't mention oil drilling. When a reporter asked him if he would reinstate the moratorium, he said he wasn't happy that the moratorium was allowed to lapse in Congress without a broader thought to how the country was going to reduce dependence on fossil fuels.
He reiterated his campaign position that he was open to the idea of offshore drilling if it was part of a comprehensive package, adding that he would turn over the question to his team.
In the 1970s and 1980s, before the moratorium on offshore drilling fully took effect, the federal government produced a series of maps showing areas in California of prospective interest to the oil industry. Those maps offer clues to where oil companies would bid if they had the opportunity.
Last proposed lease
The last proposed lease sale in 1987, thwarted by the moratorium, would have opened 6.5 million acres off the North Coast. Off Mendocino and Humboldt counties, the tracts for sale lay from 3 to 27 miles offshore, and some of the 24 planned platforms, some of them 300 feet tall and each with dozens of wells, would have been visible from land.
Tourism and commercial fisheries would have been affected, according to an environmental review then, while as many as 240 new oil tanker trips from Fort Bragg and Eureka to the San Francisco Bay refineries were predicted under the full development scenario. The probability of one or more spills occurring would be 94 percent for accidents involving 1,000 barrels or more, according to documents.
Rep. Lois Capps, D-Santa Barbara, a member of the House Natural Resources Committee, recently said oil drilling will be part of a comprehensive energy policy focusing on renewable sources, but she would like to see drilling occur only on land and in the Gulf of Mexico where infrastructure is in place.
Capps well remembers the Santa Barbara spill almost 40 years ago.
"I was living in Goleta. I just had two children, and my husband was a young professor at UC Santa Barbara. It was a devastating experience," she said. "The birds and other animals got trapped in the oil. So many people waded out in boots just inch by inch trying to rescue our wildlife. It ruined our tourism for many years.
"I think about it all the time, especially last week when we had had a spill at the same platform. It was a small spill, 1,000 gallons, but it was a wake-up call."
E-mail Jane Kay at jkay@sfchronicle.com.
Sunday, December 28, 2008
Natural Gas OPEC Dream of Tehran
The Seventh Ministerial Meeting of the Gas Exporting Countries Forum (GECF) adopted a charter with an agreement reached to set up an executive office and a Doha-based secretariat. Although the Russian energy minister said after the meeting that a “new international organization” had come into being, Russia media, however, remained unoptimistic for the future prospects of GECF.
Founded in Tehran in 2001, the now-15 member GECF groups Russia, the biggest natural gas producer on earth, Iran, Qatar, Libya, Nigeria, Venezuela and other leading gas producing nations, which account for 70 percent of the world’s gas reserves. On January 29, 2007, Iran’s supreme leader Ayatollah Ali Khamenei publicly proposed for the first time the formation of a gas-export cartel to the visiting Igor Ivan, Secretary of Russia’s Security Council, and Vladimir Putin, the Russian president then, responded to it with an immediate endorsement.
On October 21 this year, Russia, Iran and Qatar held a meeting in Tehran, which touched off speculations that they intended to form a gas cartel in a bid to control international gas prices, but the Russia side gave a prompt denial.
In order to avert worries of natural gas producers, Russia has all along been unwilling to place “Gas OPEC” on a par with (Oil) OPEC. But the Russia side claims that the natural gas exporting countries forum would not be a cartel with the characteristics of engrossing the market. The charter adopted at the forum does not specify any obligations of its member countries with regard to quotas for exploration and price consultations, but those present at the forum discussed the issue on pricing mechanism for gas.
Russia, which has so far undoubtedly played a crucial, vital role in the development process of GECF, actively spurs the development of GECF primarily for ensuring its own economic interests since energy export is one of its major pillars for boosting economy. With a drastic decline in oil prices amid the deteriorating global financial crisis, Russia, as a big crude oil and gas exporter, hopes to stabilize natural gas prices and guarantee the steady operation of its domestic economy. At the GECF meeting, Prime Minister Vladimir Putin warned that the era of cheap natural gas was ending because of multi-billion dollar investments needed to develop the industry.
In face of an emerging gas cartel, or a gas OPEC, some countries, and especially European natural gas consuming nations, have expressed their concerns. To date, 70 percent of the natural gas production in Russia is exported to Europe, accounting for 40 percent of the continent’s natural gas consumption. So, European countries are indeed highly dependent on Russian energy and Russian gas in particular, and they regard it as Russia’s trump or “master card”. Consequently, a vital topic now lying before them is how to gradually lessen their dependence on Russian energy supplies.
Nevertheless, industry insiders acknowledge that natural gas, unlike crude oil, has to be pipelined and consumed instantly, and so it is difficult to store it to effect interference with prices. In fact, most natural gas deals are often irrevocable, long-term fixed price contracts signed between buyers and sellers. GECF member countries may go in for a wide-ranging cooperation in the gas extraction and liquefying process, but they are unlikely to form an OPEC-style pricing alliance.
As a matter of fact, GECF is rift with internal disparities at the present phase of development, according to an in-depth analysis of Russia’s “Independence” newspaper, Nezavisimaya Gazeta. For instance, it further explains, Russia hopes to base the GECF Secretariat in St. Petersburg on its territory, but the voting at the forum would ultimately seat it in Qatari capital city of Doha.
In a short run, GECF can possibly do something in the use of technologies, such as doing market surveys or reducing frictions among natural gas exporting countries, and it is expected to play a real, substantial role a decade later. At present, owing to the linkage between global gas prices and oil prices, however, natural gas markets have been seriously affected at a time when global financial crisis is slumping oil prices, and this precisely poses a challenge to GECF as well.
Founded in Tehran in 2001, the now-15 member GECF groups Russia, the biggest natural gas producer on earth, Iran, Qatar, Libya, Nigeria, Venezuela and other leading gas producing nations, which account for 70 percent of the world’s gas reserves. On January 29, 2007, Iran’s supreme leader Ayatollah Ali Khamenei publicly proposed for the first time the formation of a gas-export cartel to the visiting Igor Ivan, Secretary of Russia’s Security Council, and Vladimir Putin, the Russian president then, responded to it with an immediate endorsement.
On October 21 this year, Russia, Iran and Qatar held a meeting in Tehran, which touched off speculations that they intended to form a gas cartel in a bid to control international gas prices, but the Russia side gave a prompt denial.
In order to avert worries of natural gas producers, Russia has all along been unwilling to place “Gas OPEC” on a par with (Oil) OPEC. But the Russia side claims that the natural gas exporting countries forum would not be a cartel with the characteristics of engrossing the market. The charter adopted at the forum does not specify any obligations of its member countries with regard to quotas for exploration and price consultations, but those present at the forum discussed the issue on pricing mechanism for gas.
Russia, which has so far undoubtedly played a crucial, vital role in the development process of GECF, actively spurs the development of GECF primarily for ensuring its own economic interests since energy export is one of its major pillars for boosting economy. With a drastic decline in oil prices amid the deteriorating global financial crisis, Russia, as a big crude oil and gas exporter, hopes to stabilize natural gas prices and guarantee the steady operation of its domestic economy. At the GECF meeting, Prime Minister Vladimir Putin warned that the era of cheap natural gas was ending because of multi-billion dollar investments needed to develop the industry.
In face of an emerging gas cartel, or a gas OPEC, some countries, and especially European natural gas consuming nations, have expressed their concerns. To date, 70 percent of the natural gas production in Russia is exported to Europe, accounting for 40 percent of the continent’s natural gas consumption. So, European countries are indeed highly dependent on Russian energy and Russian gas in particular, and they regard it as Russia’s trump or “master card”. Consequently, a vital topic now lying before them is how to gradually lessen their dependence on Russian energy supplies.
Nevertheless, industry insiders acknowledge that natural gas, unlike crude oil, has to be pipelined and consumed instantly, and so it is difficult to store it to effect interference with prices. In fact, most natural gas deals are often irrevocable, long-term fixed price contracts signed between buyers and sellers. GECF member countries may go in for a wide-ranging cooperation in the gas extraction and liquefying process, but they are unlikely to form an OPEC-style pricing alliance.
As a matter of fact, GECF is rift with internal disparities at the present phase of development, according to an in-depth analysis of Russia’s “Independence” newspaper, Nezavisimaya Gazeta. For instance, it further explains, Russia hopes to base the GECF Secretariat in St. Petersburg on its territory, but the voting at the forum would ultimately seat it in Qatari capital city of Doha.
In a short run, GECF can possibly do something in the use of technologies, such as doing market surveys or reducing frictions among natural gas exporting countries, and it is expected to play a real, substantial role a decade later. At present, owing to the linkage between global gas prices and oil prices, however, natural gas markets have been seriously affected at a time when global financial crisis is slumping oil prices, and this precisely poses a challenge to GECF as well.
Saturday, December 27, 2008
Natural Gas Production Up in the USA
By KRISTEN HAYS
Copyright 2008 Houston Chronicle News Services
Dec. 25, 2008, 6:25PM
Natural gas prices have fallen dramatically this year much like crude prices, but shrinking demand is only one culprit. The other is a gas glut from a boom in U.S. production.
"The industry is suffering from its own success in some respects," said Karr Ingham, head of Ingham Economic Reporting in Amarillo. "We’ve added a lot of natural gas production in Texas and elsewhere just because of high prices."
Those prices, which surpassed $13 per million British thermal units last summer, have fallen below $6 as U.S. production grew while demand decreased amid the recession in the second half of the year.
Producers are slashing capital budgets and idling rigs so they can drill within their means amid the credit crunch as well as reduce output.
But so far, production hasn’t slowed enough to compensate for oversupply. Output is on track to exceed 60 billion cubic feet per day next year — the highest in 35 years, Merrill Lynch analyst Francisco Blanch said in a note to investors.
"We have too much gas, exacerbated by the potential for sustained demand weakness," said David Pursell, an analyst with Tudor, Pickering, Holt & Co. Securities in Houston. "We know we have demand weakness now. The question is, how long will it be soft?"
This year’s boom doubled gas drilling activity from what it was 10 years ago, largely because of technological advances that allowed producers to pull more gas from thick shale rock. The Energy Department this week said the amount of gas in storage in the week ending Dec. 19 dropped 147 billion cubic feet to 3.02 trillion cubic feet, from 3.008 trillion cubic feet a year ago.
Pursell said the current pace of drilling combined with soft demand suggests the market is oversupplied by about 4 billion cubic feet of gas per day despite Gulf of Mexico production interruptions because of hurricanes Gustav and Ike.
Rig count drops
According to Baker Hughes, which has tracked North American rig activity since 1944, the nation’s rig count — which includes both oil and gas rigs, though most drill for gas — has dropped to 1,764 from its September peak of 2,031, as of the Dec. 19 count.
But Pursell said Tudor, Pickering is projecting production in excess of the nation’s operational storage capacity of 3.85 trillion cubic feet next year even if 400 rigs are idled to flatten production while industrial demand drops 2.5 percent and electricity demand remains flat. That outlook suggests more than 400 rigs need to stop drilling or the industry could face having to shut in production in August through October, he said.
Simmons & Company International said in a report this month that if 700 gas rigs stop drilling, production should start declining in May and set the stage for large withdrawals of stored gas for the 2009-2010 winter. Then prices would rise, and give drillers incentive to bring rigs back on.
So Pursell said a bitter cold winter alone won’t be enough to bring supply back in sync with demand.
"In a world where people are in hunker-down mode — and I would argue that most people are in hunker-down mode in this economy — you probably see people turn the thermostat down a little bit," Pursell said.
Richard Mason, publisher of the Land Rig Newsletter in Lubbock, said this year’s drilling boom stemmed from rising prices that encouraged more activity, particularly in hot natural gas shale plays like the Barnett around Forth Worth and others in Arkansas, Oklahoma and Colorado. Potential reserves in emerging shale plays also gained attention, including the Haynesville in East Texas and Louisiana and the Marcellus in the Northeast.
When natural gas hit $8, then $9, and then double digits, companies leased more land — or jumped in the shale game — and hired more rigs.
Also, in February, cold weather prompted robust draws from stored gas, further stimulating production.
"We saw a response in the April and May rig count that began one of the most dynamic rises in the modern era," Mason said. "It was incredible to see."
He said much of the current pullback is seasonal as drilling budgets run their annual course, particularly for independents—companies with exploration and production, but no refining — and smaller, privately owned players.
Comparable to May
Mason noted the current rig count is comparable to levels in May and is still high compared to 2006 and 2007. Some analysts say a 400-rig pullback like that projected by Tudor, Pickering could lower production enough to bring supply in line with demand.
Others have called for more dramatic pullbacks of 800 to 1,000 rigs, to half or less than half of those currently pumping.
"The challenge is, there is so much uncertainty in the general economy right now, it’s hard to apply rationality to how severe the pullback in drilling activity is going to be," Mason said. "Operators are acting like consumers. They’re just shutting down spending and waiting to see how things are going to work out."
Oklahoma City-based Chesapeake Energy’s about-face to its aggressive drilling expansion earlier this year exemplifies the pullback, though it is far from the only company to idle rigs and slash spending. In November, Chesapeake said it would cut its drilling budget through 2010 by 31 percent, or nearly $3 billion, and cut its acquisition budget by $2.2 billion, or 78 percent. This month the company updated those figures, noting that since July, it has cut its drilling and acquisition budgets in 2009 and 2010 by $9.8 billion, or 58 percent.
In addition, Chesapeake is cutting operating rigs from a peak of 158 in August to 110 to 115 in the first quarter of next year. The company said the moves would ensure it will operate within its cash flow and eliminate its dependence on asset sales to fund its operations.
El Paso Corp., Exco Resources, Williams Cos. and Canada’s EnCana are among other companies that have announced capital spending cuts that include idling natural gas rigs.
"This happened so quickly that it has been very difficult for the industry, particularly the service industry, to grasp the magnitude of what happened before our very eyes," Mason said.
More room to contract But analysts say production still needs to contract further.
Blanch, the Merrill analyst, said the raft of announcements from producers to cut spending on drilling and leases doesn’t mean the cutbacks will be big or immediate. He said rigs will likely decline in the Rocky Mountains or the Midwest, but not necessarily in more highly producing areas like the Barnett.
"We expect more drilling announcements from producers," Blanch said.
Mason said this year’s gradual dropoff of rigs likely will burst into a "big unwind" in the first quarter of 2009, with rigs dropping by the dozens. However, a lot of that will be rig contracts at high-cost wells winding down with operators unwilling to re-sign them in the current price and economic climate.
But not all companies will react the same way, he said. The oil majors’ operations are consistent in any price environment. Independents, particularly those like Chesapeake that outspent their cash flow during the boom, are scaling back. But the small, private operators that fluctuate with seasons and price are expected to bolt in droves, Mason said.
"In early 2009, those privately held guys will give up the ghost and precipitate the cascade," he said. Harder to power back up
However, Ingham said too much contraction as prices fall would bring about a dramatic spike if supply trails demand amid an economic recovery.
"When prices drop as far as quickly as they have, we tend to react to that fairly quickly — idle rigs quickly, and essentially power down the industry," he said.
"Then when economics change, or we have a cold winter and we’re not prepared for that on the supply side, we see price spikes again. We can power down the industry a lot faster than we can power it up again."
kristen.hays@chron.com
Copyright 2008 Houston Chronicle News Services
Dec. 25, 2008, 6:25PM
Natural gas prices have fallen dramatically this year much like crude prices, but shrinking demand is only one culprit. The other is a gas glut from a boom in U.S. production.
"The industry is suffering from its own success in some respects," said Karr Ingham, head of Ingham Economic Reporting in Amarillo. "We’ve added a lot of natural gas production in Texas and elsewhere just because of high prices."
Those prices, which surpassed $13 per million British thermal units last summer, have fallen below $6 as U.S. production grew while demand decreased amid the recession in the second half of the year.
Producers are slashing capital budgets and idling rigs so they can drill within their means amid the credit crunch as well as reduce output.
But so far, production hasn’t slowed enough to compensate for oversupply. Output is on track to exceed 60 billion cubic feet per day next year — the highest in 35 years, Merrill Lynch analyst Francisco Blanch said in a note to investors.
"We have too much gas, exacerbated by the potential for sustained demand weakness," said David Pursell, an analyst with Tudor, Pickering, Holt & Co. Securities in Houston. "We know we have demand weakness now. The question is, how long will it be soft?"
This year’s boom doubled gas drilling activity from what it was 10 years ago, largely because of technological advances that allowed producers to pull more gas from thick shale rock. The Energy Department this week said the amount of gas in storage in the week ending Dec. 19 dropped 147 billion cubic feet to 3.02 trillion cubic feet, from 3.008 trillion cubic feet a year ago.
Pursell said the current pace of drilling combined with soft demand suggests the market is oversupplied by about 4 billion cubic feet of gas per day despite Gulf of Mexico production interruptions because of hurricanes Gustav and Ike.
Rig count drops
According to Baker Hughes, which has tracked North American rig activity since 1944, the nation’s rig count — which includes both oil and gas rigs, though most drill for gas — has dropped to 1,764 from its September peak of 2,031, as of the Dec. 19 count.
But Pursell said Tudor, Pickering is projecting production in excess of the nation’s operational storage capacity of 3.85 trillion cubic feet next year even if 400 rigs are idled to flatten production while industrial demand drops 2.5 percent and electricity demand remains flat. That outlook suggests more than 400 rigs need to stop drilling or the industry could face having to shut in production in August through October, he said.
Simmons & Company International said in a report this month that if 700 gas rigs stop drilling, production should start declining in May and set the stage for large withdrawals of stored gas for the 2009-2010 winter. Then prices would rise, and give drillers incentive to bring rigs back on.
So Pursell said a bitter cold winter alone won’t be enough to bring supply back in sync with demand.
"In a world where people are in hunker-down mode — and I would argue that most people are in hunker-down mode in this economy — you probably see people turn the thermostat down a little bit," Pursell said.
Richard Mason, publisher of the Land Rig Newsletter in Lubbock, said this year’s drilling boom stemmed from rising prices that encouraged more activity, particularly in hot natural gas shale plays like the Barnett around Forth Worth and others in Arkansas, Oklahoma and Colorado. Potential reserves in emerging shale plays also gained attention, including the Haynesville in East Texas and Louisiana and the Marcellus in the Northeast.
When natural gas hit $8, then $9, and then double digits, companies leased more land — or jumped in the shale game — and hired more rigs.
Also, in February, cold weather prompted robust draws from stored gas, further stimulating production.
"We saw a response in the April and May rig count that began one of the most dynamic rises in the modern era," Mason said. "It was incredible to see."
He said much of the current pullback is seasonal as drilling budgets run their annual course, particularly for independents—companies with exploration and production, but no refining — and smaller, privately owned players.
Comparable to May
Mason noted the current rig count is comparable to levels in May and is still high compared to 2006 and 2007. Some analysts say a 400-rig pullback like that projected by Tudor, Pickering could lower production enough to bring supply in line with demand.
Others have called for more dramatic pullbacks of 800 to 1,000 rigs, to half or less than half of those currently pumping.
"The challenge is, there is so much uncertainty in the general economy right now, it’s hard to apply rationality to how severe the pullback in drilling activity is going to be," Mason said. "Operators are acting like consumers. They’re just shutting down spending and waiting to see how things are going to work out."
Oklahoma City-based Chesapeake Energy’s about-face to its aggressive drilling expansion earlier this year exemplifies the pullback, though it is far from the only company to idle rigs and slash spending. In November, Chesapeake said it would cut its drilling budget through 2010 by 31 percent, or nearly $3 billion, and cut its acquisition budget by $2.2 billion, or 78 percent. This month the company updated those figures, noting that since July, it has cut its drilling and acquisition budgets in 2009 and 2010 by $9.8 billion, or 58 percent.
In addition, Chesapeake is cutting operating rigs from a peak of 158 in August to 110 to 115 in the first quarter of next year. The company said the moves would ensure it will operate within its cash flow and eliminate its dependence on asset sales to fund its operations.
El Paso Corp., Exco Resources, Williams Cos. and Canada’s EnCana are among other companies that have announced capital spending cuts that include idling natural gas rigs.
"This happened so quickly that it has been very difficult for the industry, particularly the service industry, to grasp the magnitude of what happened before our very eyes," Mason said.
More room to contract But analysts say production still needs to contract further.
Blanch, the Merrill analyst, said the raft of announcements from producers to cut spending on drilling and leases doesn’t mean the cutbacks will be big or immediate. He said rigs will likely decline in the Rocky Mountains or the Midwest, but not necessarily in more highly producing areas like the Barnett.
"We expect more drilling announcements from producers," Blanch said.
Mason said this year’s gradual dropoff of rigs likely will burst into a "big unwind" in the first quarter of 2009, with rigs dropping by the dozens. However, a lot of that will be rig contracts at high-cost wells winding down with operators unwilling to re-sign them in the current price and economic climate.
But not all companies will react the same way, he said. The oil majors’ operations are consistent in any price environment. Independents, particularly those like Chesapeake that outspent their cash flow during the boom, are scaling back. But the small, private operators that fluctuate with seasons and price are expected to bolt in droves, Mason said.
"In early 2009, those privately held guys will give up the ghost and precipitate the cascade," he said. Harder to power back up
However, Ingham said too much contraction as prices fall would bring about a dramatic spike if supply trails demand amid an economic recovery.
"When prices drop as far as quickly as they have, we tend to react to that fairly quickly — idle rigs quickly, and essentially power down the industry," he said.
"Then when economics change, or we have a cold winter and we’re not prepared for that on the supply side, we see price spikes again. We can power down the industry a lot faster than we can power it up again."
kristen.hays@chron.com
Friday, December 26, 2008
Turkey Looking for more Natural Gas
STANBUL, Dec 25 (Reuters) - Turkey's Energy Minister Hilmi Guler will shortly visit Iraq to sign a deal on natural gas transportation, Prime Minister Tayyip Erdogan said on Thursday.
"The Iraqis view the idea of transporting Iraqi natural gas through Turkey positively. Our Energy Minister will go to Baghdad to negotiate the issue and sign a deal," he told reporters.
Last month Turkish state firms Botas and TPAO and global energy company Royal Dutch Shell announced they had formed a natural gas exploration and marketing partnership in Iraq.
Iraq, reliant for revenue on oil, needs major investment to boost output after years of sanctions and war. (Reporting by Alexandra Hudson; Editing by Andrew Callus)
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"The Iraqis view the idea of transporting Iraqi natural gas through Turkey positively. Our Energy Minister will go to Baghdad to negotiate the issue and sign a deal," he told reporters.
Last month Turkish state firms Botas and TPAO and global energy company Royal Dutch Shell announced they had formed a natural gas exploration and marketing partnership in Iraq.
Iraq, reliant for revenue on oil, needs major investment to boost output after years of sanctions and war. (Reporting by Alexandra Hudson; Editing by Andrew Callus)
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Thursday, December 25, 2008
Natural Gas Storage Levels Down This Week
Associated Press
DOE says natural gas supplies dropped last week
By ERNEST SCHEYDER , 12.24.08, 12:07 PM EST
pic
Natural gas storage levels in the U.S. tumbled last week, but remain 3.4 percent above the five-year average for this time of year, a government report said Wednesday.
The Energy Department's Energy Information Administration said in its weekly report that natural gas inventories held in underground storage in the lower 48 states slipped by 147 billion cubic feet to about 3.02 trillion cubic feet for the week ending Dec. 19.
Analysts had expected a drop of between 142 billion and 147 billion cubic feet, according to a survey by Platts, the energy information arm of McGraw-Hill (nyse: MHP - news - people ) Cos.
The inventory level was above the five-year average of about 2.92 trillion cubic feet, but below last year's storage level of about 3.06 trillion cubic feet, according to the government data.
Natural gas fell 13.5 cents to $5.602 per 1,000 cubic feet on the New York Mercantile Exchange.
DOE says natural gas supplies dropped last week
By ERNEST SCHEYDER , 12.24.08, 12:07 PM EST
pic
Natural gas storage levels in the U.S. tumbled last week, but remain 3.4 percent above the five-year average for this time of year, a government report said Wednesday.
The Energy Department's Energy Information Administration said in its weekly report that natural gas inventories held in underground storage in the lower 48 states slipped by 147 billion cubic feet to about 3.02 trillion cubic feet for the week ending Dec. 19.
Analysts had expected a drop of between 142 billion and 147 billion cubic feet, according to a survey by Platts, the energy information arm of McGraw-Hill (nyse: MHP - news - people ) Cos.
The inventory level was above the five-year average of about 2.92 trillion cubic feet, but below last year's storage level of about 3.06 trillion cubic feet, according to the government data.
Natural gas fell 13.5 cents to $5.602 per 1,000 cubic feet on the New York Mercantile Exchange.
Wednesday, December 24, 2008
Capital Drives Natural Gas Exploration
Posted Tue Dec 23, 01:46 pm ET
Posted By: Sheraz Mian
Zacks.com
After remaining essentially flat for almost 9 years (1998-2006), natural gas production in the Lower 48 started trending up last year and really accelerated this year. Production increased around 5.5% in 2007 and remains on track to grow in excess of 9% in 2008.
What has been driving this growth spurt? And, given the economy's cloudy outlook and continued credit-market turmoil, can this production growth momentum be sustained going forward?
Favorable prices prompted increased natural gas drilling, with the total onshore rig count making a new all-time high this year. Also, technological improvements enabled the industry to economically develop resources that could not be cost effectively developed in the past. At the forefront of the technological improvement has been the widespread use of 'horizontal' drilling (as against the conventional vertical drilling) to develop the so-called unconventional resources. Horizontal drilling rigs now account for approximately 28% of the total rig count, up from the 1990's average of about 5% of the total. Texas has been at the forefront of the current growth spurt, accounting for roughly half of the total growth this year. The state now accounts for about one-third of all Lower 48 natural gas production. The bulk of Texas' growth resulted from the use of horizontal drilling of a long-known geological formation, the Barnett Shale, most of which is located beneath the city of Fort Worth.
A combination of low prices and restricted access to capital is expected to reverse the recent production-growth momentum. Exploration and production companies, the dominant natural gas producers in the U.S., were spending heavily on drilling activities in the last few years. Over the last 2 years, companies in our E&P coverage universe were spending, on average, about 25% in excess of their internal cash flows, with the capital markets making up the shortfall. With that avenue essentially closed, E&P companies are constrained to live within their means; by cutting back capital expenditure plans for 2009. The resultant fall off in drilling (the rig count could drop in excess of 30% from its peak) is expected to reverse the production-growth momentum of the last 2 years.
We believe that reduced natural gas production over the coming quarters will set the commodity up for a rise in prices late next year and into 2010. Our top E&P picks, XTO Energy (XTO), EOG Resources (EOG), EnCana (ECA), and Chesapeake Energy (CHK), are a play on this outlook.
Posted By: Sheraz Mian
Zacks.com
After remaining essentially flat for almost 9 years (1998-2006), natural gas production in the Lower 48 started trending up last year and really accelerated this year. Production increased around 5.5% in 2007 and remains on track to grow in excess of 9% in 2008.
What has been driving this growth spurt? And, given the economy's cloudy outlook and continued credit-market turmoil, can this production growth momentum be sustained going forward?
Favorable prices prompted increased natural gas drilling, with the total onshore rig count making a new all-time high this year. Also, technological improvements enabled the industry to economically develop resources that could not be cost effectively developed in the past. At the forefront of the technological improvement has been the widespread use of 'horizontal' drilling (as against the conventional vertical drilling) to develop the so-called unconventional resources. Horizontal drilling rigs now account for approximately 28% of the total rig count, up from the 1990's average of about 5% of the total. Texas has been at the forefront of the current growth spurt, accounting for roughly half of the total growth this year. The state now accounts for about one-third of all Lower 48 natural gas production. The bulk of Texas' growth resulted from the use of horizontal drilling of a long-known geological formation, the Barnett Shale, most of which is located beneath the city of Fort Worth.
A combination of low prices and restricted access to capital is expected to reverse the recent production-growth momentum. Exploration and production companies, the dominant natural gas producers in the U.S., were spending heavily on drilling activities in the last few years. Over the last 2 years, companies in our E&P coverage universe were spending, on average, about 25% in excess of their internal cash flows, with the capital markets making up the shortfall. With that avenue essentially closed, E&P companies are constrained to live within their means; by cutting back capital expenditure plans for 2009. The resultant fall off in drilling (the rig count could drop in excess of 30% from its peak) is expected to reverse the production-growth momentum of the last 2 years.
We believe that reduced natural gas production over the coming quarters will set the commodity up for a rise in prices late next year and into 2010. Our top E&P picks, XTO Energy (XTO), EOG Resources (EOG), EnCana (ECA), and Chesapeake Energy (CHK), are a play on this outlook.
Tuesday, December 23, 2008
India Natural Gas Exploration Licenses Granted
MUMBAI (India) - INDIA has awarded exploration rights for 44 oil and gas blocks, the Ministry of Petroleum & Natural Gas said on Monday.
The state-run Oil & Natural Gas Corporation Ltd. and its partners dominated, sweeping up licenses for 20 of the blocks.
Australia's BHP Billiton and its local partner GVK Oil & Gas Ltd., a subsidiary of GVK Power & Infrastructure Limited, took licenses for seven deep-water blocks.
Reliance Industries Ltd. and BP Plc. got rights for a single deep-water area off India's eastern coast.
Reliance has a 70 per cent interest and BP holds the remaining 30 per cent stake in the 1,949 sq. kilometre block, which lies about 100 kilometres away from existing deep water oil and gas discoveries in India's Krishna Godavari basin, the companies said on Monday.
Reliance spokesman E. Mohan Reddy said it was too early to tell how the falling price of oil might affect the feasibility of deep-water drilling, which is costly and technologically complex.
He said the companies are now surveying the area to see how much oil and gas they can extract. Once that's complete, he said, 'we'll see whether it's worth it.' The ministry said it expects US$8.3 billion (S$12.03 billion) in exploration expenditure. It received bids from 95 companies, including 21 foreign firms, the highest for any licensing round. -- AP
The state-run Oil & Natural Gas Corporation Ltd. and its partners dominated, sweeping up licenses for 20 of the blocks.
Australia's BHP Billiton and its local partner GVK Oil & Gas Ltd., a subsidiary of GVK Power & Infrastructure Limited, took licenses for seven deep-water blocks.
Reliance Industries Ltd. and BP Plc. got rights for a single deep-water area off India's eastern coast.
Reliance has a 70 per cent interest and BP holds the remaining 30 per cent stake in the 1,949 sq. kilometre block, which lies about 100 kilometres away from existing deep water oil and gas discoveries in India's Krishna Godavari basin, the companies said on Monday.
Reliance spokesman E. Mohan Reddy said it was too early to tell how the falling price of oil might affect the feasibility of deep-water drilling, which is costly and technologically complex.
He said the companies are now surveying the area to see how much oil and gas they can extract. Once that's complete, he said, 'we'll see whether it's worth it.' The ministry said it expects US$8.3 billion (S$12.03 billion) in exploration expenditure. It received bids from 95 companies, including 21 foreign firms, the highest for any licensing round. -- AP
Monday, December 22, 2008
U.S. Natural Gas at $5.26/mmBtu
By Reg Curren
Dec. 22 (Bloomberg) -- Natural gas fell for a fourth day on concern a recession in the U.S. will reduce demand, keeping stockpiles above average for this time of year.
Demand from companies including Dow Chemical Co., the largest U.S. chemical maker, and Chrysler LLC, the third biggest U.S. carmaker, is declining as production is idled. Industrial consumption accounted for 29 percent of U.S. gas demand in 2007, according to Energy Department data. About 20 percent went for residential use.
“The natural gas market is caught in a bearish trend as a result of the weakening economy,” Peter Beutel, president of Cameron Hanover Inc., an energy consulting company in New Canaan, Connecticut, said in a morning note today.
Natural gas for January delivery fell 7.8 cents, or 1.5 percent, to $5.256 per million British thermal units at 1:05 p.m. on the New York Mercantile Exchange. It earlier dropped to $5.21, the lowest since Aug. 27, 2007. Gas futures declined 2.8 percent last week.
Dow said Dec. 8 it plans to close 20 plants and idle 180 others. The company uses gas and petroleum to power its operations and as raw materials for plastics and chemicals. Chrysler closed all 30 of its plants for at least a month starting Dec. 19 amid slumping demand.
U.S. gas stockpiles in the week ended Dec. 12 were 3.7 percent above the five-year average, greater than a 3.5 percent surplus a week earlier, the Energy Department said last week. Supplies were 3.167 trillion cubic feet.
Prices Fall
Gas prices fell as a cold snap gripped parts of the U.S. including the Midwest, where 72 percent of households rely on the fuel for heating.
“One would expect because of the cold weather, you’d see more strength in natural gas,” said Fadel Gheit, director of oil and gas research at Oppenheimer & Co. in New York. “It’s not making an impact because gas is very susceptible to economic activity. Industrial demand is coming down very sharply.”
A recession in the U.S. has cut demand from industrial users of the fuel, keeping supplies at above-average amounts for this time of year. Usage may slow more over the next two weeks as the Christmas and New Year’s holidays prompt plant closures in much of the U.S. and Canada.
“The cold isn’t an issue today when it comes to gas, the market is looking beyond that,” said Phil Flynn, senior trader at Alaron Trading Corp. in Chicago. “It’s more focused on weak demand in the economy and that’s going to put more pressure on the downside.”
Industry Slowdown
Output from the U.S. steel industry, another large user of natural gas, was down 45 percent from a year earlier in the week ended Dec. 13, according to the American Iron and Steel Institute.
Industrial gas consumption was about 1 billion cubic feet a day, or 6.3 percent lower in November than a year earlier, Cameron Horwitz, an analyst at Sun Trust Robinson Humphrey in Houston, said in a report earlier this month.
Demand may fall later this week as higher temperatures are expected to move into the Midwest and Northeast.
The low temperature in Chicago may rise to 20 degrees Fahrenheit (minus 7 Celsius) by Dec. 26 from tomorrow’s forecast minimum of 2 degrees, according to forecaster MDA Federal Inc.’s EarthSat Energy Weather of Rockville, Maryland.
“The weather maps look to be warming up,” said Michael Rose, a director of trading at Angus Jackson Inc. in Fort Lauderdale, Florida.
To contact the reporter on this story: Reg Curren in Calgary at rcurren@bloomberg.net.
Dec. 22 (Bloomberg) -- Natural gas fell for a fourth day on concern a recession in the U.S. will reduce demand, keeping stockpiles above average for this time of year.
Demand from companies including Dow Chemical Co., the largest U.S. chemical maker, and Chrysler LLC, the third biggest U.S. carmaker, is declining as production is idled. Industrial consumption accounted for 29 percent of U.S. gas demand in 2007, according to Energy Department data. About 20 percent went for residential use.
“The natural gas market is caught in a bearish trend as a result of the weakening economy,” Peter Beutel, president of Cameron Hanover Inc., an energy consulting company in New Canaan, Connecticut, said in a morning note today.
Natural gas for January delivery fell 7.8 cents, or 1.5 percent, to $5.256 per million British thermal units at 1:05 p.m. on the New York Mercantile Exchange. It earlier dropped to $5.21, the lowest since Aug. 27, 2007. Gas futures declined 2.8 percent last week.
Dow said Dec. 8 it plans to close 20 plants and idle 180 others. The company uses gas and petroleum to power its operations and as raw materials for plastics and chemicals. Chrysler closed all 30 of its plants for at least a month starting Dec. 19 amid slumping demand.
U.S. gas stockpiles in the week ended Dec. 12 were 3.7 percent above the five-year average, greater than a 3.5 percent surplus a week earlier, the Energy Department said last week. Supplies were 3.167 trillion cubic feet.
Prices Fall
Gas prices fell as a cold snap gripped parts of the U.S. including the Midwest, where 72 percent of households rely on the fuel for heating.
“One would expect because of the cold weather, you’d see more strength in natural gas,” said Fadel Gheit, director of oil and gas research at Oppenheimer & Co. in New York. “It’s not making an impact because gas is very susceptible to economic activity. Industrial demand is coming down very sharply.”
A recession in the U.S. has cut demand from industrial users of the fuel, keeping supplies at above-average amounts for this time of year. Usage may slow more over the next two weeks as the Christmas and New Year’s holidays prompt plant closures in much of the U.S. and Canada.
“The cold isn’t an issue today when it comes to gas, the market is looking beyond that,” said Phil Flynn, senior trader at Alaron Trading Corp. in Chicago. “It’s more focused on weak demand in the economy and that’s going to put more pressure on the downside.”
Industry Slowdown
Output from the U.S. steel industry, another large user of natural gas, was down 45 percent from a year earlier in the week ended Dec. 13, according to the American Iron and Steel Institute.
Industrial gas consumption was about 1 billion cubic feet a day, or 6.3 percent lower in November than a year earlier, Cameron Horwitz, an analyst at Sun Trust Robinson Humphrey in Houston, said in a report earlier this month.
Demand may fall later this week as higher temperatures are expected to move into the Midwest and Northeast.
The low temperature in Chicago may rise to 20 degrees Fahrenheit (minus 7 Celsius) by Dec. 26 from tomorrow’s forecast minimum of 2 degrees, according to forecaster MDA Federal Inc.’s EarthSat Energy Weather of Rockville, Maryland.
“The weather maps look to be warming up,” said Michael Rose, a director of trading at Angus Jackson Inc. in Fort Lauderdale, Florida.
To contact the reporter on this story: Reg Curren in Calgary at rcurren@bloomberg.net.
Haynesville Shale Crown Jewel of Natural Gas
Shreveporttimes.com
BATON ROUGE — A huge drop in the prices of oil and natural gas, consumers driving less and a tight lending market have the oil and gas industry in a bind at the end of a roller coaster year.
After riding high earlier in the year with oil selling for as much as $145 a barrel and natural gas at $13.31 per MMBtu, industry officials have seen oil prices plunge 73 percent and natural gas 58 percent.
"Forty dollar oil is not good," said Larry Wall, spokesman for the Louisiana Mid-Continent Oil and Gas Association. "If you're a consumer buying gasoline, it's good," but for royalty owners who receive monthly checks for production on their property and for companies drilling the wells, "it's very bad.
"It needs to be $60 to $75 a barrel to encourage new projects," he said.
The latest crash, Wall said, was in 1997-98 when oil bottomed out at about $10 a barrel. He said that won't happen again, but the price could get a little lower than it is.
The market price Friday dropped below $40, and some analysts predicted a drop to $20 during 2009.
However, Wall predicts "it will bounce back in a short time, possibly in a couple of months. It hit $50 for a short time the other day."
The Oil and Petroleum Exporting Countries keep trying to drive up the price by cutting back supplies. So far, it's not working, said Wall and Don Briggs, president of the Louisiana Oil and Gas Association. OPEC announced a 2.2 million barrel per day cutback, but prices fell the next day.
The main reason OPEC has not been successful in driving up the price, Briggs said, is "they all cheat on each other." Although they agree to cut production, they don't. "None of them trust each other."
Consumption of gasoline is a major factor in the price of oil, Briggs said. When demand was high, supply dwindled.
"When oil hit $127 (a barrel), people pulled back and consumed less oil," he said. About $30 of that amount was inflated by market speculation of higher demand, and "prices contracted and started falling because demand went down. People are doing less traveling and they're worried about their jobs. Overnight, our tanks were overflowing. We have a 2-to-2½ million barrel surplus."
"The drop in prices is one thing, but what's really kicking us between the eyes is there's no money" to borrow for exploration, Briggs said. "Credit is drying up. The industry is slashing drilling budgets drastically."
Currently, 1,790 drilling rigs are working in the United States — 1,379 drilling for natural gas and 411 for oil, according to Baker Hughes, a worldwide oilfield service company.
Briggs said he has heard predictions that as many as 1,000 of those rigs could be shut down. "I really don't believe that. But we could lose 600 rigs" drilling new wells.
Baker Hughes reported that Louisiana had 172 rigs working Dec. 19. Of those, 87 were in north Louisiana, nine were in south Louisiana inland waters, 23 were on land in south Louisiana and 53 were offshore. Two weeks earlier, 185 were reported working.
Wall said that doesn't necessarily mean that the rigs won't come back.
"At this time of year, rigs are sometimes moved for tax purposes," he said. Parishes have different tax policies, so a rig might be moved across parish lines until tax assessments are completed at the end of the year.
Briggs said some companies are pulling back their exploration of natural gas in shale deposits in Texas, Pennsylvania, Wyoming and Colorado, but "companies are keeping their rigs in the Haynesville Shale" in northwest Louisiana. "North Louisiana will flourish and hardly feel the crunch because the Haynesville economics are so good. They're high-producing gas wells."
Of the 3 million acres in the Haynesville Shale, 2.8 million have leases, he said.
Briggs predicts that the rest of the state won't be so lucky and "in south Louisiana and inland waters, budgets will be cut. There could be some layoffs," but scientists employed by oil and gas producers will be safe. "Most companies will tighten their belts and work through this."
Steady production is depleting the world's supply of oil at a rate of about 7 percent a year, he said. Worldwide, about 85 million barrels of oil are produced yearly, and production drops about 6 million barrels per year. To maintain the same production, new sources have to be found.
"U.S. production is 5 million barrels a day," Briggs said. "So, just to stay afloat, companies have to find a whole new United States production of oil every year. As a nation, energy security is not going to come from oil."
Unlike oil, natural gas supplies are plentiful, Briggs said.
"Natural gas is the green fuel and there's plenty of it," he said, and the Haynesville Shale is "the crown jewel."
BATON ROUGE — A huge drop in the prices of oil and natural gas, consumers driving less and a tight lending market have the oil and gas industry in a bind at the end of a roller coaster year.
After riding high earlier in the year with oil selling for as much as $145 a barrel and natural gas at $13.31 per MMBtu, industry officials have seen oil prices plunge 73 percent and natural gas 58 percent.
"Forty dollar oil is not good," said Larry Wall, spokesman for the Louisiana Mid-Continent Oil and Gas Association. "If you're a consumer buying gasoline, it's good," but for royalty owners who receive monthly checks for production on their property and for companies drilling the wells, "it's very bad.
"It needs to be $60 to $75 a barrel to encourage new projects," he said.
The latest crash, Wall said, was in 1997-98 when oil bottomed out at about $10 a barrel. He said that won't happen again, but the price could get a little lower than it is.
The market price Friday dropped below $40, and some analysts predicted a drop to $20 during 2009.
However, Wall predicts "it will bounce back in a short time, possibly in a couple of months. It hit $50 for a short time the other day."
The Oil and Petroleum Exporting Countries keep trying to drive up the price by cutting back supplies. So far, it's not working, said Wall and Don Briggs, president of the Louisiana Oil and Gas Association. OPEC announced a 2.2 million barrel per day cutback, but prices fell the next day.
The main reason OPEC has not been successful in driving up the price, Briggs said, is "they all cheat on each other." Although they agree to cut production, they don't. "None of them trust each other."
Consumption of gasoline is a major factor in the price of oil, Briggs said. When demand was high, supply dwindled.
"When oil hit $127 (a barrel), people pulled back and consumed less oil," he said. About $30 of that amount was inflated by market speculation of higher demand, and "prices contracted and started falling because demand went down. People are doing less traveling and they're worried about their jobs. Overnight, our tanks were overflowing. We have a 2-to-2½ million barrel surplus."
"The drop in prices is one thing, but what's really kicking us between the eyes is there's no money" to borrow for exploration, Briggs said. "Credit is drying up. The industry is slashing drilling budgets drastically."
Currently, 1,790 drilling rigs are working in the United States — 1,379 drilling for natural gas and 411 for oil, according to Baker Hughes, a worldwide oilfield service company.
Briggs said he has heard predictions that as many as 1,000 of those rigs could be shut down. "I really don't believe that. But we could lose 600 rigs" drilling new wells.
Baker Hughes reported that Louisiana had 172 rigs working Dec. 19. Of those, 87 were in north Louisiana, nine were in south Louisiana inland waters, 23 were on land in south Louisiana and 53 were offshore. Two weeks earlier, 185 were reported working.
Wall said that doesn't necessarily mean that the rigs won't come back.
"At this time of year, rigs are sometimes moved for tax purposes," he said. Parishes have different tax policies, so a rig might be moved across parish lines until tax assessments are completed at the end of the year.
Briggs said some companies are pulling back their exploration of natural gas in shale deposits in Texas, Pennsylvania, Wyoming and Colorado, but "companies are keeping their rigs in the Haynesville Shale" in northwest Louisiana. "North Louisiana will flourish and hardly feel the crunch because the Haynesville economics are so good. They're high-producing gas wells."
Of the 3 million acres in the Haynesville Shale, 2.8 million have leases, he said.
Briggs predicts that the rest of the state won't be so lucky and "in south Louisiana and inland waters, budgets will be cut. There could be some layoffs," but scientists employed by oil and gas producers will be safe. "Most companies will tighten their belts and work through this."
Steady production is depleting the world's supply of oil at a rate of about 7 percent a year, he said. Worldwide, about 85 million barrels of oil are produced yearly, and production drops about 6 million barrels per year. To maintain the same production, new sources have to be found.
"U.S. production is 5 million barrels a day," Briggs said. "So, just to stay afloat, companies have to find a whole new United States production of oil every year. As a nation, energy security is not going to come from oil."
Unlike oil, natural gas supplies are plentiful, Briggs said.
"Natural gas is the green fuel and there's plenty of it," he said, and the Haynesville Shale is "the crown jewel."
Sunday, December 21, 2008
Virginia Natural Gas Drilling Debate Begins
WASHINGTON (CNN) -- Remember "drill, baby drill"? In its last weeks in office, the Bush administration is starting to make it happen by quietly starting the process of exploration and drilling off the coast of Virginia.
The move means that President-elect Barack Obama and brand new interior secretary nominee Ken Salazar -- a Democratic senator from Colorado -- will have to jump feet-first into the decades-old debate over offshore oil drilling. It's an issue where the two disagreed at one point.
Wait. Virginia?
The state is ground zero for the drilling debate because of possible reserves off the coast and what energy experts see as a friendlier government than elsewhere.
The U.S. Interior Department has completed the first step, closing a public comment period on the proposal to lease 2.9 million acres of ocean to natural gas and oil companies. The pie-shaped area begins 50 miles off Virginia's coast, straight out from Virginia Beach on the south and across from Virginia's boundary on the Delmarva peninsula to the north.
"The East Coast really has not been looked at for 30 years," said Randall Luthi, who heads up the drilling plan as director of Interior's Minerals Management Service. Luthi spoke from his Washington office to CNN Radio.
"Our best guess is that area could contain about 130 million barrels of oil and 1.14 trillion cubic feet of natural gas," he said.
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Such an oil find would be small compared with the estimated 40 billion barrels in the Gulf Coast. The natural gas is more substantial. But both are symbolic of a rare window of opportunity for the energy industry.
A two-fold ban on Outer Continental Shelf drilling ended in just the past two months.
As the price of gas surged past $4 a gallon this summer, U.S. drilling became a hot political issue. President Bush responded by repealing a presidential offshore drilling ban put in place by his father. Then in October, a gridlocked Congress let a separate drilling moratorium expire after 26 years on the books.
Back in Virginia, environmentalists echo their Southwestern counterparts, calling the offshore push a last-ditch energy grab.
"We've got an administration on its way out, trying to make its last deal for the oil and gas industry," said Glenn Besa, director of Virginia's Sierra Club chapter.
Besa pointed to what he sees as a platoon of red flags.
"The Navy has a lot of operations out there, in the area where this drilling takes place," he said, "And the North Atlantic right whale, there's only 300 or 400 of those individual whales left, and they migrate through that area as well."
The Navy has expressed concern about the prospect of drilling rigs in the area where much of its Norfolk fleet trains. NASA has objected as well because it launches satellites and low-altitude rockets from its facility on Wallops Island, Virginia.
The state's Democratic governor, Tim Kaine, asked the Interior Department to let Virginia research possible natural gas reserves. But the agency went further, opening the process for oil and gas leasing.
Luthi defends the move without hesitation. "Oil and gas are going to continue to be a major part of our energy needs in this country," he said, "for at least the next generation."
The Minerals and Management chief calls this the start of a long research and regulation period. He said that under ideal conditions, actual leasing of the ocean area could not begin until 2011.
But, the next administration could either promote or stop the process cold.
Obama could simply direct the Department of the Interior to freeze the offshore process. He could also issue another presidential ban on offshore drilling.
Or he could let the idea go forward, something his new nominee to head the Interior Department has favored.
Earlier this year, Salazar was part of a bipartisan group of lawmakers that wanted to open up Outer Continental Shelf drilling in exchange for more investment in low-carbon technology. Video Watch: Salazar pick criticized »
At the time, then-Sen. Obama was in the other camp, sharply opposed to offshore drilling. But that changed during the campaign, when gas prices were high and politically explosive. Candidate Obama said that he rethought his position and that "responsible" offshore exploration is part of the total energy picture.
The bold-faced question mark is, where will Obama stand on January 20 when he takes office?
Besa is counting on the incoming president to lean left and stop Virginia drilling. "I do think that the environmental community's voice will be heard," he said.
But in the Bush camp, Luthi is trying to turn the change in power to his advantage, "That's one reason we started [this process], was to give the new administration an option." he said.
The move means that President-elect Barack Obama and brand new interior secretary nominee Ken Salazar -- a Democratic senator from Colorado -- will have to jump feet-first into the decades-old debate over offshore oil drilling. It's an issue where the two disagreed at one point.
Wait. Virginia?
The state is ground zero for the drilling debate because of possible reserves off the coast and what energy experts see as a friendlier government than elsewhere.
The U.S. Interior Department has completed the first step, closing a public comment period on the proposal to lease 2.9 million acres of ocean to natural gas and oil companies. The pie-shaped area begins 50 miles off Virginia's coast, straight out from Virginia Beach on the south and across from Virginia's boundary on the Delmarva peninsula to the north.
"The East Coast really has not been looked at for 30 years," said Randall Luthi, who heads up the drilling plan as director of Interior's Minerals Management Service. Luthi spoke from his Washington office to CNN Radio.
"Our best guess is that area could contain about 130 million barrels of oil and 1.14 trillion cubic feet of natural gas," he said.
Don't Miss
* Lawsuit seeks to halt gas and oil drilling in Utah
* Gas prices slip below $2 nationally
Such an oil find would be small compared with the estimated 40 billion barrels in the Gulf Coast. The natural gas is more substantial. But both are symbolic of a rare window of opportunity for the energy industry.
A two-fold ban on Outer Continental Shelf drilling ended in just the past two months.
As the price of gas surged past $4 a gallon this summer, U.S. drilling became a hot political issue. President Bush responded by repealing a presidential offshore drilling ban put in place by his father. Then in October, a gridlocked Congress let a separate drilling moratorium expire after 26 years on the books.
Back in Virginia, environmentalists echo their Southwestern counterparts, calling the offshore push a last-ditch energy grab.
"We've got an administration on its way out, trying to make its last deal for the oil and gas industry," said Glenn Besa, director of Virginia's Sierra Club chapter.
Besa pointed to what he sees as a platoon of red flags.
"The Navy has a lot of operations out there, in the area where this drilling takes place," he said, "And the North Atlantic right whale, there's only 300 or 400 of those individual whales left, and they migrate through that area as well."
The Navy has expressed concern about the prospect of drilling rigs in the area where much of its Norfolk fleet trains. NASA has objected as well because it launches satellites and low-altitude rockets from its facility on Wallops Island, Virginia.
The state's Democratic governor, Tim Kaine, asked the Interior Department to let Virginia research possible natural gas reserves. But the agency went further, opening the process for oil and gas leasing.
Luthi defends the move without hesitation. "Oil and gas are going to continue to be a major part of our energy needs in this country," he said, "for at least the next generation."
The Minerals and Management chief calls this the start of a long research and regulation period. He said that under ideal conditions, actual leasing of the ocean area could not begin until 2011.
But, the next administration could either promote or stop the process cold.
Obama could simply direct the Department of the Interior to freeze the offshore process. He could also issue another presidential ban on offshore drilling.
Or he could let the idea go forward, something his new nominee to head the Interior Department has favored.
Earlier this year, Salazar was part of a bipartisan group of lawmakers that wanted to open up Outer Continental Shelf drilling in exchange for more investment in low-carbon technology. Video Watch: Salazar pick criticized »
At the time, then-Sen. Obama was in the other camp, sharply opposed to offshore drilling. But that changed during the campaign, when gas prices were high and politically explosive. Candidate Obama said that he rethought his position and that "responsible" offshore exploration is part of the total energy picture.
The bold-faced question mark is, where will Obama stand on January 20 when he takes office?
Besa is counting on the incoming president to lean left and stop Virginia drilling. "I do think that the environmental community's voice will be heard," he said.
But in the Bush camp, Luthi is trying to turn the change in power to his advantage, "That's one reason we started [this process], was to give the new administration an option." he said.
Saturday, December 20, 2008
PXP & XTO Natural Gas Strength
Barrons
CRT Capital Group
OUR NEGATIVE-123 BILLION CUBIC FEET FORECAST [for natural gas next week from working gas in storage] is fundamentally bearish against the five-year average, but an improvement nonetheless from last week, as the first triple-digit withdrawal of the season is shaping up.
We've made downward adjustments to our forecast to account for both nuclear generation increases and additional supply created by what we believe to be gas plants leaving ethane and other liquids in the pipeline due to low natural-gas-liquids prices. While Nymex gas prices are below current costs to incent drilling, we expect lower power costs and rig rates to reduce cost structures in 2009, allowing lower pricing lows, but also making existing price hedges more attractive.
Companies such as Plains Exploration & Production (ticker: PXP) and XTO Energy (XTO) -- both Buy-rated -- feature particularly strong 2009 hedging positions, which we have highlighted in this low-commodity-price environment.
Cold weather moving West to East this week provided some relief to beleaguered Rockies producers, enabling spot prices to post impressive week-over-week gains (up 23% at Opal, Wyo., and up 9.8% at Blanco, N.M., in the San Juan Basin). Below-seasonal norm temperatures have gripped much of the nation this week, with snow in the Pacific Northwest and in the higher elevations of the Southwest, subzero temps in the Upper Midwest, and snow/ice in the Northeast. We are expecting a strong storage withdrawal in next week's report.
The Organization of the Petroleum Exporting Countries dominated the news Wednesday, with the group announcing a larger-than-expected 2.46 million-barrel-per-day cut to supply (from current 27.308 million barrels per day to 24.845 million barrels per day) starting Jan. 1. Russia also signaled its willingness to reduce supply further in 2009, after cutting 350,000 barrels per day in November.
Despite the news, Nymex January crude fell $3.54 per barrel, reportedly on skepticism about OPEC's ability to adhere to its own cuts. Such concern today seems overdone in our view, as OPEC production cheating is a regular occurrence, and a well known part of the equation. Crude inventory figures did not help prices either, rising again this week by 525,000 barrels. Gasoline inventories also increased, while refinery utilization was down 3.32% week over week.
After years of covering Plains Exploration, this week we wrote an update note that is practically a reinitiation piece.
These days, exceptional hedging, differentiated project access, and growth momentum from partnered development and exploration projects stand out from the group. Plausible near-term catalysts include details of ongoing production results in the Haynesville Shale with Chesapeake Energy (CHK), and at Flatrock with McMoRan Exploration (MMR), and finally a possible permit to drill offshore California.
Longer term, we suspect monetizing in-hand discoveries with Royal Dutch Shell (RDSA), an exploration play in Vietnam, and a nonoperated interest in the Madden Field operated by ConocoPhillips (COP) are all on the table. We also propose that Plains and Chesapeake Energy might revive a master limited partnership concept in the Haynesville over time, highlighted in our note.
CRT Capital Group
OUR NEGATIVE-123 BILLION CUBIC FEET FORECAST [for natural gas next week from working gas in storage] is fundamentally bearish against the five-year average, but an improvement nonetheless from last week, as the first triple-digit withdrawal of the season is shaping up.
We've made downward adjustments to our forecast to account for both nuclear generation increases and additional supply created by what we believe to be gas plants leaving ethane and other liquids in the pipeline due to low natural-gas-liquids prices. While Nymex gas prices are below current costs to incent drilling, we expect lower power costs and rig rates to reduce cost structures in 2009, allowing lower pricing lows, but also making existing price hedges more attractive.
Companies such as Plains Exploration & Production (ticker: PXP) and XTO Energy (XTO) -- both Buy-rated -- feature particularly strong 2009 hedging positions, which we have highlighted in this low-commodity-price environment.
Cold weather moving West to East this week provided some relief to beleaguered Rockies producers, enabling spot prices to post impressive week-over-week gains (up 23% at Opal, Wyo., and up 9.8% at Blanco, N.M., in the San Juan Basin). Below-seasonal norm temperatures have gripped much of the nation this week, with snow in the Pacific Northwest and in the higher elevations of the Southwest, subzero temps in the Upper Midwest, and snow/ice in the Northeast. We are expecting a strong storage withdrawal in next week's report.
The Organization of the Petroleum Exporting Countries dominated the news Wednesday, with the group announcing a larger-than-expected 2.46 million-barrel-per-day cut to supply (from current 27.308 million barrels per day to 24.845 million barrels per day) starting Jan. 1. Russia also signaled its willingness to reduce supply further in 2009, after cutting 350,000 barrels per day in November.
Despite the news, Nymex January crude fell $3.54 per barrel, reportedly on skepticism about OPEC's ability to adhere to its own cuts. Such concern today seems overdone in our view, as OPEC production cheating is a regular occurrence, and a well known part of the equation. Crude inventory figures did not help prices either, rising again this week by 525,000 barrels. Gasoline inventories also increased, while refinery utilization was down 3.32% week over week.
After years of covering Plains Exploration, this week we wrote an update note that is practically a reinitiation piece.
These days, exceptional hedging, differentiated project access, and growth momentum from partnered development and exploration projects stand out from the group. Plausible near-term catalysts include details of ongoing production results in the Haynesville Shale with Chesapeake Energy (CHK), and at Flatrock with McMoRan Exploration (MMR), and finally a possible permit to drill offshore California.
Longer term, we suspect monetizing in-hand discoveries with Royal Dutch Shell (RDSA), an exploration play in Vietnam, and a nonoperated interest in the Madden Field operated by ConocoPhillips (COP) are all on the table. We also propose that Plains and Chesapeake Energy might revive a master limited partnership concept in the Haynesville over time, highlighted in our note.
Friday, December 19, 2008
Marcellus Shale Natural Gas in Pennsylvania
WEXFORD, Pa., Dec 18, 2008 /PRNewswire via COMTEX/ -- PaMarcellus.com to Provide Details on Natural Gas Development in Pennsylvania
The Marcellus Shale Committee (MSC) today announced the launch of its new Web site, www.PaMarcellus.com, which will serve as an information resource for people interested in learning about the development of natural gas from the Marcellus Shale formation in Pennsylvania.
"Our Web site provides an opportunity for Pennsylvanians to learn about all aspects of producing natural gas from the Marcellus Shale," said Ray Walker, MSC Co-Chair and Vice President of Appalachia Shale for Range Resources. "Whether you are interested in learning more about the property leasing process, drilling procedures or land restoration efforts, all of the details will be available on the site."
The site provides a full range of information on the Marcellus Shale formation, how natural gas is extracted from the shale while protecting the environment, why MSC values the communities where its members do business, and the opportunities that the Commonwealth and its residents can realize in the coming years and decades through natural gas exploration and production. The pages highlighting process, protection, community and opportunity can be printed to provide detailed fact sheets on important topics related to the Marcellus Shale development.
"We will continually update this resource as development of the Marcellus Shale increases in the state of Pennsylvania over the coming years," said Rich Weber, Co-Chair of the MSC and President of Atlas Energy Resources. "As more natural gas drilling activity occurs, we want www.PaMarcellus.com to serve as a fact-focused information source for individuals and communities across the Commonwealth."
About the Marcellus Shale Committee
Formed in 2008, the Marcellus Shale committee represents the oil and gas industry in Pennsylvania on matters pertaining to the acquisition, exploration, drilling, and development of the Marcellus Shale natural gas resource and provides a unified voice before all state, county, and local government or regulatory bodies. The committee, sponsored jointly by the Pennsylvania Oil and Gas Association and the Independent Oil and Gas Association of Pennsylvania, includes small independent producers with historical expertise in the Pennsylvania oil and gas fields and larger national companies dedicated to bringing their industry experience and resources to achieve common goals.
SOURCE The Marcellus Shale Committee
http://www.PaMarcellus.com
The Marcellus Shale Committee (MSC) today announced the launch of its new Web site, www.PaMarcellus.com, which will serve as an information resource for people interested in learning about the development of natural gas from the Marcellus Shale formation in Pennsylvania.
"Our Web site provides an opportunity for Pennsylvanians to learn about all aspects of producing natural gas from the Marcellus Shale," said Ray Walker, MSC Co-Chair and Vice President of Appalachia Shale for Range Resources. "Whether you are interested in learning more about the property leasing process, drilling procedures or land restoration efforts, all of the details will be available on the site."
The site provides a full range of information on the Marcellus Shale formation, how natural gas is extracted from the shale while protecting the environment, why MSC values the communities where its members do business, and the opportunities that the Commonwealth and its residents can realize in the coming years and decades through natural gas exploration and production. The pages highlighting process, protection, community and opportunity can be printed to provide detailed fact sheets on important topics related to the Marcellus Shale development.
"We will continually update this resource as development of the Marcellus Shale increases in the state of Pennsylvania over the coming years," said Rich Weber, Co-Chair of the MSC and President of Atlas Energy Resources. "As more natural gas drilling activity occurs, we want www.PaMarcellus.com to serve as a fact-focused information source for individuals and communities across the Commonwealth."
About the Marcellus Shale Committee
Formed in 2008, the Marcellus Shale committee represents the oil and gas industry in Pennsylvania on matters pertaining to the acquisition, exploration, drilling, and development of the Marcellus Shale natural gas resource and provides a unified voice before all state, county, and local government or regulatory bodies. The committee, sponsored jointly by the Pennsylvania Oil and Gas Association and the Independent Oil and Gas Association of Pennsylvania, includes small independent producers with historical expertise in the Pennsylvania oil and gas fields and larger national companies dedicated to bringing their industry experience and resources to achieve common goals.
SOURCE The Marcellus Shale Committee
http://www.PaMarcellus.com
Natural Gas Production to Grow to 2010
The coldest temperatures of the season to date covered much of the northern half of the country this report week, boosting demand related to space heating on both coasts and across the Northern Plains and Midwest population centers. Prices increased throughout the country outside the Northeast, with the biggest increases occurring for supplies from the Rocky Mountains (particularly for delivery into the Northwest). During the report week, the Henry Hub spot price increased $0.11 per million Btu (MMBtu) to $5.79.
* At the New York Mercantile Exchange (NYMEX), futures prices decreased slightly for the report week as the current economic downturn continued. Expected to accompany this downturn is a likely large-scale reduction in demand for all energy products, which is affecting pricing for energy in forward markets. The futures contract for January 2009 delivery decreased by 6.7 cents per MMBtu on the week to $5.619.
* As of Friday, December 12, working gas in underground storage was 3,167 billion cubic feet (Bcf), which is 3.7 percent above the 5-year (2003-2007) average.
* The price of West Texas Intermediate (WTI) crude oil decreased on the week by $2.93 per barrel to $40.17, or $6.93 per MMBtu. This is the lowest price for WTI crude oil since July 2004.
A major weather front entered the Pacific Northwest, Northern Plains, and Midwest, then moved eastward during the report week, bringing the coldest temperatures of the season to date to much of the Lower 48 States. Increased space-heating demand in consuming regions led to gains in spot-market prices in regions outside the Northeast with prices in the Midcontinent and Rockies producing regions generally increasing by between 15 and 25 percent. Prices for supplies from the Gulf of Mexico region generally advanced less than 5 percent. Along the Gulf Coast in Louisiana and in East Texas, the average increase was $0.08 and $0.23 per MMBtu, respectively, resulting in average regional prices of $5.74 and $5.56. The gains appeared mostly related to short-term weather dynamics, rather than a change in the outlook for longer-term market conditions, with many of the factors leading to a massive decline in prices over the past several months remaining firmly in place. During the week, the current economic downturn continued to suggest a steep decline in demand, particularly in the industrial sector, with many companies announcing layoffs and closures of manufacturing plants around the country.
Natural gas prices now are likely to end the year lower than they were at the beginning, despite having reached historically high levels of more than $13 per MMBtu as recently as the beginning of July 2008. The spot price at the Henry Hub decreased by $7.52 per MMBtu, or 56 percent, since the peak price of $13.31 reached on July 2. The current Henry Hub price of $5.79 per MMBtu is lower than the level at the first of the year by $2.08 or 26 percent. The volatility in natural gas prices over the course of the year reflects the rapidly changing markets for crude oil and energy products. Reduced prices for natural gas in recent months relate to an improved outlook for supplies, particularly because of reported increases in domestic production at unconventional fields such as the prolific Barnett Shale in Northeast Texas. Through the first 9 months of 2008, domestic production increased 7.2 percent in comparison with the same period in 2007, despite some production being shut-in as a result of hurricanes in September, according to the November edition of EIAs Natural Gas Monthly.
During the report week, price increases were largest in the Rockies, where the advent of colder weather has eased concerns over an abundance of regional supplies and limited options for storage. At Rockies trading locations, the average price increased on the week by $1.11 per MMBtu, or 23 percent, to $5.87. For supplies moving westward, weekly gains were particularly strong. The price for supply off Northwest Pipeline Corporation in Washington for delivery into Sumas increased by $4.62 per MMBtu to $10.37. The Sumas market price, which was the highest price in the country yesterday (December 16), likely reflected the extreme weather in Seattle, Washington, this week, as well as competition for supplies with consumers in Canada, where the temperature was well below zero degrees. With this significant weekly increase in Rockies prices, the average price in the region was higher than the Henry Hub price by 8 cents per MMBtu, or 1.4 percent. Rockies spot prices are often the lowest in the country, trading this fall at price levels roughly 40 percent below the Henry Hub price.
Although prices in the Northeast were the highest of all regions, averaging $6.58 per MMBtu, the Northeast was the only region where prices declined over the report week. The decline was limited to an average of 4 cents per MMBtu, or less than 1 percent, as temperatures in the Northeast during this report week were not as extreme as in the middle and western portions of the country. Moreover, while the weather was significantly cold, a large electrical outage in New England may have limited demand for natural gas as a fuel for electric generation. The average Northeast price as of yesterday was 84 cents per MMBtu higher than the average Louisiana price. Although this differential has surged often in the winter when temperatures in the Northeast fall and pipeline capacity into the region becomes congested, the recent relatively moderate temperatures have limited the upward price pressure in this region.
At the NYMEX, the price of the near-month contract (for January delivery) decreased 6.7 cents per MMBtu during the report week to $5.619. The decrease was attributed to expected lower consumption as a result of the current economic downturn, as well as a short-term reprieve from the extreme cold experienced in some parts of the country in recent days. The January contract yesterday finished trading at less than 40 percent of its record high price (of $14.52 per MMBtu) established just 5 months ago, prior to the buildup of concerns over the state of the economy and higher-than-average levels of natural gas in underground storage. Downward price pressure also appears related to an improved domestic production outlook and declines in the crude oil price, which decreased this week to its lowest level in more than 4 years. At the end of trading yesterday, the 12-month strip, which is the average for natural gas futures contracts over the next year, was priced at $6.13 per MMBtu, a decrease of about $0.08, or 1.3 percent, since last Wednesday.
Storage
Working gas in storage totaled 3,167 Bcf as of Friday, December 12, 2008, according to EIAs Weekly Natural Gas Storage Report (see Storage Figure). The implied net withdrawal for the week of 124 Bcf is the largest yet this heating season, but slightly less than the 128 Bcf that was withdrawn both last year and on average over the past 5 years. The aggregate level of supplies in underground storage now exceeds the 5-year average by 3.7 percent. Although the current aggregate level is below last years aggregate level by 1.3 percent, storage levels in the West and East regions of the country exceed last years levels by 3.9 and 0.1 percent, respectively. (A description and map of the storage regions are available at http://www.eia.doe.gov/oil_gas/natural_gas/ngs/notes.html.) Only the volume of storage in the Production region is below the volume last year at this time (by 5.9 percent). Because the Producing region includes more salt-cavern facilities (which allow for greater cycling of injections and withdrawals than reservoirs or aquifers), storage levels in this region may reflect more short-term trading opportunities, rather than preparations to meet space-heating seasonal demand.
This weeks withdrawal from storage reflects a number of market conditions. During the week ending Friday, December 12, significant volumes of natural gas were still shut-in because of damage caused by hurricanes in the fall. During the week ending December 12, an estimated 10.5 Bcf of potential supplies was shut-in in the Federal offshore Gulf of Mexico, possibly requiring industry to withdraw more from storage than they would have otherwise. Another likely factor influencing the size of the withdrawal was colder-than-average weather during the week in all regions east of the Rocky Mountains. As indicated by National Weather Service degree-day data, the number of heating degree-days totaled 9.6 percent above normal for the country as a whole, with regional differences of as much as 21 percent higher than average. In general, the average overall temperature for the week was 35.9 degrees Fahrenheit, about 2.7 degrees below normal see Temperature Maps and Data.
* At the New York Mercantile Exchange (NYMEX), futures prices decreased slightly for the report week as the current economic downturn continued. Expected to accompany this downturn is a likely large-scale reduction in demand for all energy products, which is affecting pricing for energy in forward markets. The futures contract for January 2009 delivery decreased by 6.7 cents per MMBtu on the week to $5.619.
* As of Friday, December 12, working gas in underground storage was 3,167 billion cubic feet (Bcf), which is 3.7 percent above the 5-year (2003-2007) average.
* The price of West Texas Intermediate (WTI) crude oil decreased on the week by $2.93 per barrel to $40.17, or $6.93 per MMBtu. This is the lowest price for WTI crude oil since July 2004.
A major weather front entered the Pacific Northwest, Northern Plains, and Midwest, then moved eastward during the report week, bringing the coldest temperatures of the season to date to much of the Lower 48 States. Increased space-heating demand in consuming regions led to gains in spot-market prices in regions outside the Northeast with prices in the Midcontinent and Rockies producing regions generally increasing by between 15 and 25 percent. Prices for supplies from the Gulf of Mexico region generally advanced less than 5 percent. Along the Gulf Coast in Louisiana and in East Texas, the average increase was $0.08 and $0.23 per MMBtu, respectively, resulting in average regional prices of $5.74 and $5.56. The gains appeared mostly related to short-term weather dynamics, rather than a change in the outlook for longer-term market conditions, with many of the factors leading to a massive decline in prices over the past several months remaining firmly in place. During the week, the current economic downturn continued to suggest a steep decline in demand, particularly in the industrial sector, with many companies announcing layoffs and closures of manufacturing plants around the country.
Natural gas prices now are likely to end the year lower than they were at the beginning, despite having reached historically high levels of more than $13 per MMBtu as recently as the beginning of July 2008. The spot price at the Henry Hub decreased by $7.52 per MMBtu, or 56 percent, since the peak price of $13.31 reached on July 2. The current Henry Hub price of $5.79 per MMBtu is lower than the level at the first of the year by $2.08 or 26 percent. The volatility in natural gas prices over the course of the year reflects the rapidly changing markets for crude oil and energy products. Reduced prices for natural gas in recent months relate to an improved outlook for supplies, particularly because of reported increases in domestic production at unconventional fields such as the prolific Barnett Shale in Northeast Texas. Through the first 9 months of 2008, domestic production increased 7.2 percent in comparison with the same period in 2007, despite some production being shut-in as a result of hurricanes in September, according to the November edition of EIAs Natural Gas Monthly.
During the report week, price increases were largest in the Rockies, where the advent of colder weather has eased concerns over an abundance of regional supplies and limited options for storage. At Rockies trading locations, the average price increased on the week by $1.11 per MMBtu, or 23 percent, to $5.87. For supplies moving westward, weekly gains were particularly strong. The price for supply off Northwest Pipeline Corporation in Washington for delivery into Sumas increased by $4.62 per MMBtu to $10.37. The Sumas market price, which was the highest price in the country yesterday (December 16), likely reflected the extreme weather in Seattle, Washington, this week, as well as competition for supplies with consumers in Canada, where the temperature was well below zero degrees. With this significant weekly increase in Rockies prices, the average price in the region was higher than the Henry Hub price by 8 cents per MMBtu, or 1.4 percent. Rockies spot prices are often the lowest in the country, trading this fall at price levels roughly 40 percent below the Henry Hub price.
Although prices in the Northeast were the highest of all regions, averaging $6.58 per MMBtu, the Northeast was the only region where prices declined over the report week. The decline was limited to an average of 4 cents per MMBtu, or less than 1 percent, as temperatures in the Northeast during this report week were not as extreme as in the middle and western portions of the country. Moreover, while the weather was significantly cold, a large electrical outage in New England may have limited demand for natural gas as a fuel for electric generation. The average Northeast price as of yesterday was 84 cents per MMBtu higher than the average Louisiana price. Although this differential has surged often in the winter when temperatures in the Northeast fall and pipeline capacity into the region becomes congested, the recent relatively moderate temperatures have limited the upward price pressure in this region.
At the NYMEX, the price of the near-month contract (for January delivery) decreased 6.7 cents per MMBtu during the report week to $5.619. The decrease was attributed to expected lower consumption as a result of the current economic downturn, as well as a short-term reprieve from the extreme cold experienced in some parts of the country in recent days. The January contract yesterday finished trading at less than 40 percent of its record high price (of $14.52 per MMBtu) established just 5 months ago, prior to the buildup of concerns over the state of the economy and higher-than-average levels of natural gas in underground storage. Downward price pressure also appears related to an improved domestic production outlook and declines in the crude oil price, which decreased this week to its lowest level in more than 4 years. At the end of trading yesterday, the 12-month strip, which is the average for natural gas futures contracts over the next year, was priced at $6.13 per MMBtu, a decrease of about $0.08, or 1.3 percent, since last Wednesday.
Storage
Working gas in storage totaled 3,167 Bcf as of Friday, December 12, 2008, according to EIAs Weekly Natural Gas Storage Report (see Storage Figure). The implied net withdrawal for the week of 124 Bcf is the largest yet this heating season, but slightly less than the 128 Bcf that was withdrawn both last year and on average over the past 5 years. The aggregate level of supplies in underground storage now exceeds the 5-year average by 3.7 percent. Although the current aggregate level is below last years aggregate level by 1.3 percent, storage levels in the West and East regions of the country exceed last years levels by 3.9 and 0.1 percent, respectively. (A description and map of the storage regions are available at http://www.eia.doe.gov/oil_gas/natural_gas/ngs/notes.html.) Only the volume of storage in the Production region is below the volume last year at this time (by 5.9 percent). Because the Producing region includes more salt-cavern facilities (which allow for greater cycling of injections and withdrawals than reservoirs or aquifers), storage levels in this region may reflect more short-term trading opportunities, rather than preparations to meet space-heating seasonal demand.
This weeks withdrawal from storage reflects a number of market conditions. During the week ending Friday, December 12, significant volumes of natural gas were still shut-in because of damage caused by hurricanes in the fall. During the week ending December 12, an estimated 10.5 Bcf of potential supplies was shut-in in the Federal offshore Gulf of Mexico, possibly requiring industry to withdraw more from storage than they would have otherwise. Another likely factor influencing the size of the withdrawal was colder-than-average weather during the week in all regions east of the Rocky Mountains. As indicated by National Weather Service degree-day data, the number of heating degree-days totaled 9.6 percent above normal for the country as a whole, with regional differences of as much as 21 percent higher than average. In general, the average overall temperature for the week was 35.9 degrees Fahrenheit, about 2.7 degrees below normal see Temperature Maps and Data.
Thursday, December 18, 2008
Penn Natural Gas Fees to Climb
By Rick Stouffer
TRIBUNE-REVIEW
Wednesday, December 17, 2008
The Pennsylvania Environmental Quality Board on Tuesday approved rules that would sharply increase permitting fees for companies drilling into the natural gas-rich Marcellus Shale formation.
For the average Marcellus Shale horizontal well that stretches 10,000 feet down and then across the shale formation, the permit cost next spring would jump to $2,600. That's up from the $100 fee, regardless of depth, that was adopted in 1984.
"Due to technological advances in drilling and rising natural gas prices, gas exploration in the commonwealth has increased significantly with 40,000 new drilling permits anticipated during the next three years," said John Hanger, acting secretary for the state Department of Environmental Protection.
DEP estimates the new fee structure will bring in an additional $3 million a year for the department. Proceeds will be used to hire 37 DEP staff to review Marcellus Shale permit applications and monitor drilling activities statewide.
Sixteen of the new employees are to be based in Pittsburgh, DEP spokesman Tom Rathbun said yesterday.
"We'll be hiring oil and natural gas inspectors, water quality specialists, environmental engineers, technical staff like geologists and office permitting staff," Rathbun said. Oil and natural gas inspectors will be paid between $41,017 and $62,338, the DEP said.
Trade associations and independent oil and natural gas exploration-production companies doing business in the Marcellus formation generally were supportive of the fee increase.
"The additional fees will help the DEP expand its resources to match increased activity in the Marcellus," said Matt Pitzarella, spokesman for Fort Worth-based Range Resources Corp., with an office in Cecil in Washington County. "Ultimately, this should help foster Marcellus development, which will add good-paying jobs in Pennsylvania and boost the state's economy."
Steve Rhoads, president of the Pennsylvania Oil & Gas Association, said his organization generally supports increased fees -- those pertaining strictly to Marcellus Shale drilling, and others for different types of oil and gas drilling programs.
The 20-member Environmental Quality Board, chaired by the DEP secretary, is an independent board that decides on all DEP regulations.
Rathbun said now that the board has approved the increase, it goes to the Independent Regulatory Review Commission, which considers whether all agency regulations are in the public's interest. Finally, the state attorney general must approve the increase.
Rick Stouffer can be reached at rstouffer@tribweb.com or 412-320-7853.
TRIBUNE-REVIEW
Wednesday, December 17, 2008
The Pennsylvania Environmental Quality Board on Tuesday approved rules that would sharply increase permitting fees for companies drilling into the natural gas-rich Marcellus Shale formation.
For the average Marcellus Shale horizontal well that stretches 10,000 feet down and then across the shale formation, the permit cost next spring would jump to $2,600. That's up from the $100 fee, regardless of depth, that was adopted in 1984.
"Due to technological advances in drilling and rising natural gas prices, gas exploration in the commonwealth has increased significantly with 40,000 new drilling permits anticipated during the next three years," said John Hanger, acting secretary for the state Department of Environmental Protection.
DEP estimates the new fee structure will bring in an additional $3 million a year for the department. Proceeds will be used to hire 37 DEP staff to review Marcellus Shale permit applications and monitor drilling activities statewide.
Sixteen of the new employees are to be based in Pittsburgh, DEP spokesman Tom Rathbun said yesterday.
"We'll be hiring oil and natural gas inspectors, water quality specialists, environmental engineers, technical staff like geologists and office permitting staff," Rathbun said. Oil and natural gas inspectors will be paid between $41,017 and $62,338, the DEP said.
Trade associations and independent oil and natural gas exploration-production companies doing business in the Marcellus formation generally were supportive of the fee increase.
"The additional fees will help the DEP expand its resources to match increased activity in the Marcellus," said Matt Pitzarella, spokesman for Fort Worth-based Range Resources Corp., with an office in Cecil in Washington County. "Ultimately, this should help foster Marcellus development, which will add good-paying jobs in Pennsylvania and boost the state's economy."
Steve Rhoads, president of the Pennsylvania Oil & Gas Association, said his organization generally supports increased fees -- those pertaining strictly to Marcellus Shale drilling, and others for different types of oil and gas drilling programs.
The 20-member Environmental Quality Board, chaired by the DEP secretary, is an independent board that decides on all DEP regulations.
Rathbun said now that the board has approved the increase, it goes to the Independent Regulatory Review Commission, which considers whether all agency regulations are in the public's interest. Finally, the state attorney general must approve the increase.
Rick Stouffer can be reached at rstouffer@tribweb.com or 412-320-7853.
Wednesday, December 17, 2008
Kentucky Natural Gas Plant from Coal
NEW YORK -(Dow Jones)- ConocoPhillips (COP) and Peabody Energy Corp. (BTU) said Tuesday that the companies have filed an air permit to build a plant in Kentucky that would convert coal to natural gas.
The project could be the first in a build-out of coal-to-natural-gas facilities by ConocoPhillips and Peabody in the U.S., said Vic Svec, a spokesman for St. Louis-based Peabody. The companies are still conducting a feasibility study to determine whether they'll go forward with the Kentucky plant, however.
"We'd certainly like to view this project as a scaleable technology," Svec said.
Svec declined to estimate the cost of the Kentucky plant. Houston-based ConocoPhillips and Peabody won't have a clear idea of the cost until they complete the feasibility study and assess fluctuating commodities prices, he said.
The companies expect the permitting process in Kentucky to take one to two years, he added.
The plant would use ConocoPhillips' proprietary technology to gasify coal, transforming into pipeline-quality natural gas. Unlike Integrated Gasification Combined Cycle technology, which produces a synthetic gas that can be used only in power plants, gas created at the ConocoPhillips-Peabody facility could be sent to consumers as heating fuel, Svec said.
The companies also are evaluating the possibility of storing or transporting the carbon dioxide emissions from the plant, which are expected to be 5% of those generated by a traditional coal plant of comparable size. ConocoPhillips and Peabody are funding research on carbon storage in western Kentucky through a test well project led by the Kentucky Geological Survey.
ConocoPhillips and Peabody are evaluating the coal-to-gas project despite economic uncertainty because plants would have "very long lifespans," Svec said.
"We like to look past near-term economic conditions into a time frame when these plants would be operating," he said.
-By Christine Buurma, Dow Jones Newswires; 201-938-2061; christine.buurma@ dowjones.com
The project could be the first in a build-out of coal-to-natural-gas facilities by ConocoPhillips and Peabody in the U.S., said Vic Svec, a spokesman for St. Louis-based Peabody. The companies are still conducting a feasibility study to determine whether they'll go forward with the Kentucky plant, however.
"We'd certainly like to view this project as a scaleable technology," Svec said.
Svec declined to estimate the cost of the Kentucky plant. Houston-based ConocoPhillips and Peabody won't have a clear idea of the cost until they complete the feasibility study and assess fluctuating commodities prices, he said.
The companies expect the permitting process in Kentucky to take one to two years, he added.
The plant would use ConocoPhillips' proprietary technology to gasify coal, transforming into pipeline-quality natural gas. Unlike Integrated Gasification Combined Cycle technology, which produces a synthetic gas that can be used only in power plants, gas created at the ConocoPhillips-Peabody facility could be sent to consumers as heating fuel, Svec said.
The companies also are evaluating the possibility of storing or transporting the carbon dioxide emissions from the plant, which are expected to be 5% of those generated by a traditional coal plant of comparable size. ConocoPhillips and Peabody are funding research on carbon storage in western Kentucky through a test well project led by the Kentucky Geological Survey.
ConocoPhillips and Peabody are evaluating the coal-to-gas project despite economic uncertainty because plants would have "very long lifespans," Svec said.
"We like to look past near-term economic conditions into a time frame when these plants would be operating," he said.
-By Christine Buurma, Dow Jones Newswires; 201-938-2061; christine.buurma@ dowjones.com
Tuesday, December 16, 2008
Kuwait Natural Gas Interest in USA
A Kuwaiti oil and gas producer says it has discovered nearly 142 billion cubic meters of recoverable natural gas in the southern U.S. state of Texas.
The company, Aref Energy, said Monday that its U.S. project manager is Texas-based energy giant Halliburton.
Aref Energy holds a 50 percent share in the operation in south-central Texas. The company has not named its partners in the operation.
Halliburton says it is taking measures to start gas production operations early next year.
Aref says a survey by the joint venture indicates a total of 538 billion cubic meters of natural gas at the Texas site.
The company, Aref Energy, said Monday that its U.S. project manager is Texas-based energy giant Halliburton.
Aref Energy holds a 50 percent share in the operation in south-central Texas. The company has not named its partners in the operation.
Halliburton says it is taking measures to start gas production operations early next year.
Aref says a survey by the joint venture indicates a total of 538 billion cubic meters of natural gas at the Texas site.
Monday, December 15, 2008
T. Boone Texas Natural Gas Man of the Year
Forbes.com
Miriam Marcus, 12.14.08, 06:00 PM EST
Billionaire named Texan of the Year.
Following a 43-year line of prominent Lone Star State natives, billionaire energy tycoon T. Boone Pickens has been named Texan of the Year by the Texas Legislative Conference.
Self-made billionaire and the world's 368th richest person, T. Boone Pickens will be presented with the award for Texan of the Year in March at the New Braunfels Civic and Convention Center, joining past honorees including first ladies Laura Bush and Lady Bird Johnson, among others. The Texas Legislative Conference is a nonpartisan organization of Texas business and political leaders who meet annually to discuss public policy issues.
Well-known for his wealth and experience in the oil and gas industry, Pickens, is the founder and chairman of BP Capital Management, a hedge fund that made $1.0 billion in profits in 2006 betting on crude oil, natural gas and Canadian tar sands.
In May, the 80-year-old from Dallas announced his Mesa Power's plan to spend $2.0 billion on 667 General Electric (nyse: GE - news - people )-made wind turbines, as the first phase of a four-stage effort to build the world’s largest wind farm in Texas. (See "Green Pickens.") At its expected completion in 2014, the Pampa Wind Project in the Texas Panhandle will cover 400,000 acres and will generate 4 gigawatts of energy, enough to power more than 1.3 million homes.
Wind power and natural gas are integral parts of the "Pickens Plan," a 10-year project announced in July to replace more than a third of the oil the United States imports with wind, natural gas and other green energy sources and, in the process, wean the country off of foreign petroleum imports, saving more than $230.0 billion annually. Pickens launched the plan last summer when crude prices peaked over $147 a barrel and interest in alternative energy surged. Currently, America spends $700.0 billion a year on foreign oil.
Miriam Marcus, 12.14.08, 06:00 PM EST
Billionaire named Texan of the Year.
Following a 43-year line of prominent Lone Star State natives, billionaire energy tycoon T. Boone Pickens has been named Texan of the Year by the Texas Legislative Conference.
Self-made billionaire and the world's 368th richest person, T. Boone Pickens will be presented with the award for Texan of the Year in March at the New Braunfels Civic and Convention Center, joining past honorees including first ladies Laura Bush and Lady Bird Johnson, among others. The Texas Legislative Conference is a nonpartisan organization of Texas business and political leaders who meet annually to discuss public policy issues.
Well-known for his wealth and experience in the oil and gas industry, Pickens, is the founder and chairman of BP Capital Management, a hedge fund that made $1.0 billion in profits in 2006 betting on crude oil, natural gas and Canadian tar sands.
In May, the 80-year-old from Dallas announced his Mesa Power's plan to spend $2.0 billion on 667 General Electric (nyse: GE - news - people )-made wind turbines, as the first phase of a four-stage effort to build the world’s largest wind farm in Texas. (See "Green Pickens.") At its expected completion in 2014, the Pampa Wind Project in the Texas Panhandle will cover 400,000 acres and will generate 4 gigawatts of energy, enough to power more than 1.3 million homes.
Wind power and natural gas are integral parts of the "Pickens Plan," a 10-year project announced in July to replace more than a third of the oil the United States imports with wind, natural gas and other green energy sources and, in the process, wean the country off of foreign petroleum imports, saving more than $230.0 billion annually. Pickens launched the plan last summer when crude prices peaked over $147 a barrel and interest in alternative energy surged. Currently, America spends $700.0 billion a year on foreign oil.
Sunday, December 14, 2008
Pennsylvania Natural Gas
By Darrin Youker
Reading Eagle
PICTURE ROCKS - W. Neal Barto farmed the high hills of Lycoming County, never knowing what was beneath his feet.
But three years ago, a land man from a Texas energy company told Barto his pastures sit on a veritable lake of natural gas, trapped in the rock underground.
Barto was one of the first landowners in this rural Northern Tier county to sell the mineral rights on his land. Three years later, a rush is on as energy companies scramble to secure leases and sink wells into one of the largest supplies of untapped natural gas in the country.
A formation of rock called Marcellus shale lies a mile underground. Stretching from the New York Finger Lakes to Ohio, the formation holds a vast reserve of gas. The largest concentration lies in Pennsylvania.
Pennsylvania once was a worldwide leader in fossil fuels, with its rich coal and oil reserves. The Keystone State is on the verge of again playing an important role in domestic fuel production, thanks to the massive amount of natural gas locked in the Marcellus shale.
And technology is emerging that could help recover coal and oil deposits that were believed depleted years ago.
Estimates vary, but experts believe there is enough gas in this formation to supply the country's entire natural gas needs for the next two years.
Natural gas drilling is not new in the state. Western Pennsylvania has seen it for decades. The state's oil and gas industry is seeing record numbers of new permits. Between 2000 and 2007, the number of new permits has tripled, according to a Pennsylvania Economy League study.
But the exploration of Marcellus shale is happening in places such as Lycoming County that have never before experienced such a land rush.
And experts say this massive gas reserve could help curb the nation's reliance of foreign oil.
Across the state, energy companies are sinking new wells for oil and gas production
Energy independence
America's energy independence was born in Pennsylvania. The nation's first oil well was sunk in Titusville, long before anyone heard of Texas Tea. Anthracite coal hauled from the steep mountains in northern Pennsylvania fueled the industrial revolution.
Experts predict Pennsylvania again will play a sizable role in U.S. energy independence. Tapping into the Marcellus shale formation is among the most promising developments.
"There has been a huge interest in natural gas from the Marcellus shale formation," said John Hanger, acting secretary of the state Department of Environmental Protection. "The big increase in drilling is the result of the high price of natural gas."
With this abundant supply, America could start running a substantial portion of its automotive fleet on natural gas, said Dr. Terry Englander, a Penn State geologist who has studied the Marcellus formation.
New focus on drilling
Energy companies have drilled, or are in the process of developing, about 50 new wells in the Marcellus formation, Englander said.
Reading Eagle
PICTURE ROCKS - W. Neal Barto farmed the high hills of Lycoming County, never knowing what was beneath his feet.
But three years ago, a land man from a Texas energy company told Barto his pastures sit on a veritable lake of natural gas, trapped in the rock underground.
Barto was one of the first landowners in this rural Northern Tier county to sell the mineral rights on his land. Three years later, a rush is on as energy companies scramble to secure leases and sink wells into one of the largest supplies of untapped natural gas in the country.
A formation of rock called Marcellus shale lies a mile underground. Stretching from the New York Finger Lakes to Ohio, the formation holds a vast reserve of gas. The largest concentration lies in Pennsylvania.
Pennsylvania once was a worldwide leader in fossil fuels, with its rich coal and oil reserves. The Keystone State is on the verge of again playing an important role in domestic fuel production, thanks to the massive amount of natural gas locked in the Marcellus shale.
And technology is emerging that could help recover coal and oil deposits that were believed depleted years ago.
Estimates vary, but experts believe there is enough gas in this formation to supply the country's entire natural gas needs for the next two years.
Natural gas drilling is not new in the state. Western Pennsylvania has seen it for decades. The state's oil and gas industry is seeing record numbers of new permits. Between 2000 and 2007, the number of new permits has tripled, according to a Pennsylvania Economy League study.
But the exploration of Marcellus shale is happening in places such as Lycoming County that have never before experienced such a land rush.
And experts say this massive gas reserve could help curb the nation's reliance of foreign oil.
Across the state, energy companies are sinking new wells for oil and gas production
Energy independence
America's energy independence was born in Pennsylvania. The nation's first oil well was sunk in Titusville, long before anyone heard of Texas Tea. Anthracite coal hauled from the steep mountains in northern Pennsylvania fueled the industrial revolution.
Experts predict Pennsylvania again will play a sizable role in U.S. energy independence. Tapping into the Marcellus shale formation is among the most promising developments.
"There has been a huge interest in natural gas from the Marcellus shale formation," said John Hanger, acting secretary of the state Department of Environmental Protection. "The big increase in drilling is the result of the high price of natural gas."
With this abundant supply, America could start running a substantial portion of its automotive fleet on natural gas, said Dr. Terry Englander, a Penn State geologist who has studied the Marcellus formation.
New focus on drilling
Energy companies have drilled, or are in the process of developing, about 50 new wells in the Marcellus formation, Englander said.
Saturday, December 13, 2008
Natural Gas Pipeline for Northwest Washington
Portland Business Journal
Northwest Natural Gas Co. Thursday filed an application with federal energy regulators to build its long-planned interstate gas pipeline.
The application to the Federal Energy Regulatory Commission was made by Palomar Gas Transmission LLC, a joint venture between the Portland-based gas utility (NYSE: NWN) and TransCanada Corp. If the certificate application is approved by the end of 2009, construction on the pipeline could begin in 2010 and be in service by November 2011.
The pipeline would be only the second interstate gas transmission line serving customers in the Willamette Valley and southwest Washington, the company said.
Once completed, the 36-inch diameter pipeline would stretch 217 miles from TransCanada’s Gas Transmission Northwest Pipeline in central Oregon to a point on the Columbia River northwest of Portland. It would be capable of transporting 1.3 billion cubic feet of natural gas per day.
“This project would greatly enhance service reliability to NW Natural’s 655,000 residential, commercial, and industrial customers,” Keith White, vice president and chief strategic officer for NW Natural, said in a news release. “The prospect of tapping additional sources of natural gas through Palomar would help mitigate the impact of future price volatility on NW Natural’s customers.”
The pipeline would pass through seven Oregon counties, which would realize an aggregate increase in property taxes of “several million dollars” annually, the company said. It would also create more than 2,000 temporary jobs.
Northwest Natural Gas Co. Thursday filed an application with federal energy regulators to build its long-planned interstate gas pipeline.
The application to the Federal Energy Regulatory Commission was made by Palomar Gas Transmission LLC, a joint venture between the Portland-based gas utility (NYSE: NWN) and TransCanada Corp. If the certificate application is approved by the end of 2009, construction on the pipeline could begin in 2010 and be in service by November 2011.
The pipeline would be only the second interstate gas transmission line serving customers in the Willamette Valley and southwest Washington, the company said.
Once completed, the 36-inch diameter pipeline would stretch 217 miles from TransCanada’s Gas Transmission Northwest Pipeline in central Oregon to a point on the Columbia River northwest of Portland. It would be capable of transporting 1.3 billion cubic feet of natural gas per day.
“This project would greatly enhance service reliability to NW Natural’s 655,000 residential, commercial, and industrial customers,” Keith White, vice president and chief strategic officer for NW Natural, said in a news release. “The prospect of tapping additional sources of natural gas through Palomar would help mitigate the impact of future price volatility on NW Natural’s customers.”
The pipeline would pass through seven Oregon counties, which would realize an aggregate increase in property taxes of “several million dollars” annually, the company said. It would also create more than 2,000 temporary jobs.
Friday, December 12, 2008
Colorado Legislation Anti Natural Gas?
By Mark Jaffe and John Ingold
The Denver Post
Posted: 12/11/2008 12:30:00 AM MST
Updated: 12/11/2008 02:06:09 AM MST
After an 18-month rulemaking marathon, Colorado adopted the most comprehensive state oil and gas drilling regulations in the nation Wednesday.
Republican lawmakers, however, already are vowing to make changes.
"We cannot afford to push the energy industry out of Colorado, given the current state of the economy," House Minority Leader Mike May, R-Parker, said. "And many fear that the proposed rules will do just that."
The 177 pages of rules — aimed at better managing oil and gas development, protecting wildlife, and reducing impacts on people living near drilling operations — were passed unanimously by the state's Oil and Gas Conservation Commission.
Among the protections the regulations impose are:
• A 300-foot no-drill buffer around streams used for drinking-water supplies.
• Controls on odors and dust on operations within a quarter-mile of homes in Garfield, Mesa and Rio Blanco counties — all major areas for natural- gas development.
• A requirement that drillers consult with the state Division of Wildlife on mitigation plans if they drill in designated wildlife areas.
"These rules are a model for the rest of the West," said Michael Saul, an attorney with the Rocky Mountain Natural Resource Center.
Ken Wonstolen, counsel for the Colorado Oil and Gas Association, an industry trade group, said: "There is nothing like it in the country. They are very complex."
Delays in permits seen
The industry's concern, Wonstolen said, is that the rules will greatly increase the time it takes to get drilling permits to as much as 75 days.
A survey of 13 other oil- and gas-producing states found that it took about five days for a permit, Wonstolen said.
But the average processing time in Colorado is now 65 days because of the crush in applications and limited staff, said David Neslin, director of the oil and gas commission.
In 2009 — with additional staff and the new rules — the goal is to cut processing time to 30 to 40 days, Neslin said.
Nevertheless, Republican legislators are taking aim at the rules.
"We are going to spend the first part of the legislative session dealing with the mess that is these regulations," state Sen. Josh Penry, R-Grand Junction, told an energy industry conference Tuesday.
The rules are the product of two bills passed in 2007 as the pace of drilling accelerated in the state.
Drilling permits are set to reach a record 7,870 in 2008 — up 33 percent in three years, according to the commission.
Commission revamped
The legislation directed the oil and gas commission to protect wildlife and public health by consulting with the Division of Wildlife and the Department of Public Health and Environment.
The legislation also expanded the oil and gas commission, and Gov. Bill Ritter appointed members that included environmentalists, local government and agricultural interests, as well as industry representatives.
Ritter made the new regulations one of his principal initiatives.
"These are rules that provide much more balance than we had in the face of unprecedented gas drilling," said Evan Dreyer, Ritter's spokesman.
The reconstituted commission also decided to overhaul its operating regulations and bonding requirements, which were more than a decade old.
The bills, however, also included a provision for a legislative review of the regulations.
DOW authority assailed
The rules for wildlife protection and stream buffers have drawn the most criticism.
There are concerns land could be made off-limits to drilling or landowners might be forced to accept wildlife projects on their property.
"The rules give the Division of Wildlife too much power," Penry said.
Those worries have been exacerbated by the weakening economy and fears that the rules will dampen industry activity in Colorado.
"I think there are folks on both sides of the aisle who get that," said state Sen. Greg Brophy, R-Wray.
But state Rep. Kathleen Curry, a Gunnison Democrat and a sponsor of the 2007 bills, said: "I don't think there is an appetite in the legislature for a wholesale rewrite."
Curry said the legislature would take a close look at the rules to make sure they match what lawmakers envisioned and may tweak some.
The rights of landowners potentially being overruled by a state agency is a particular concern, Curry said.
"The legislature gave us a difficult job of balancing wildlife protection and property rights, and we've tried to do that," said Harris Sherman, director of the Department of Natural Resources and chair of the commission.
As for the rules dampening industry activity, Sherman said: "What is affecting the industry is the credit crunch and the fall in commodity prices."
The spot price of natural gas on the New York Mercantile Exchange this year has fallen from $13.57 per thousand cubic feet to $5.67.
The Denver Post
Posted: 12/11/2008 12:30:00 AM MST
Updated: 12/11/2008 02:06:09 AM MST
After an 18-month rulemaking marathon, Colorado adopted the most comprehensive state oil and gas drilling regulations in the nation Wednesday.
Republican lawmakers, however, already are vowing to make changes.
"We cannot afford to push the energy industry out of Colorado, given the current state of the economy," House Minority Leader Mike May, R-Parker, said. "And many fear that the proposed rules will do just that."
The 177 pages of rules — aimed at better managing oil and gas development, protecting wildlife, and reducing impacts on people living near drilling operations — were passed unanimously by the state's Oil and Gas Conservation Commission.
Among the protections the regulations impose are:
• A 300-foot no-drill buffer around streams used for drinking-water supplies.
• Controls on odors and dust on operations within a quarter-mile of homes in Garfield, Mesa and Rio Blanco counties — all major areas for natural- gas development.
• A requirement that drillers consult with the state Division of Wildlife on mitigation plans if they drill in designated wildlife areas.
"These rules are a model for the rest of the West," said Michael Saul, an attorney with the Rocky Mountain Natural Resource Center.
Ken Wonstolen, counsel for the Colorado Oil and Gas Association, an industry trade group, said: "There is nothing like it in the country. They are very complex."
Delays in permits seen
The industry's concern, Wonstolen said, is that the rules will greatly increase the time it takes to get drilling permits to as much as 75 days.
A survey of 13 other oil- and gas-producing states found that it took about five days for a permit, Wonstolen said.
But the average processing time in Colorado is now 65 days because of the crush in applications and limited staff, said David Neslin, director of the oil and gas commission.
In 2009 — with additional staff and the new rules — the goal is to cut processing time to 30 to 40 days, Neslin said.
Nevertheless, Republican legislators are taking aim at the rules.
"We are going to spend the first part of the legislative session dealing with the mess that is these regulations," state Sen. Josh Penry, R-Grand Junction, told an energy industry conference Tuesday.
The rules are the product of two bills passed in 2007 as the pace of drilling accelerated in the state.
Drilling permits are set to reach a record 7,870 in 2008 — up 33 percent in three years, according to the commission.
Commission revamped
The legislation directed the oil and gas commission to protect wildlife and public health by consulting with the Division of Wildlife and the Department of Public Health and Environment.
The legislation also expanded the oil and gas commission, and Gov. Bill Ritter appointed members that included environmentalists, local government and agricultural interests, as well as industry representatives.
Ritter made the new regulations one of his principal initiatives.
"These are rules that provide much more balance than we had in the face of unprecedented gas drilling," said Evan Dreyer, Ritter's spokesman.
The reconstituted commission also decided to overhaul its operating regulations and bonding requirements, which were more than a decade old.
The bills, however, also included a provision for a legislative review of the regulations.
DOW authority assailed
The rules for wildlife protection and stream buffers have drawn the most criticism.
There are concerns land could be made off-limits to drilling or landowners might be forced to accept wildlife projects on their property.
"The rules give the Division of Wildlife too much power," Penry said.
Those worries have been exacerbated by the weakening economy and fears that the rules will dampen industry activity in Colorado.
"I think there are folks on both sides of the aisle who get that," said state Sen. Greg Brophy, R-Wray.
But state Rep. Kathleen Curry, a Gunnison Democrat and a sponsor of the 2007 bills, said: "I don't think there is an appetite in the legislature for a wholesale rewrite."
Curry said the legislature would take a close look at the rules to make sure they match what lawmakers envisioned and may tweak some.
The rights of landowners potentially being overruled by a state agency is a particular concern, Curry said.
"The legislature gave us a difficult job of balancing wildlife protection and property rights, and we've tried to do that," said Harris Sherman, director of the Department of Natural Resources and chair of the commission.
As for the rules dampening industry activity, Sherman said: "What is affecting the industry is the credit crunch and the fall in commodity prices."
The spot price of natural gas on the New York Mercantile Exchange this year has fallen from $13.57 per thousand cubic feet to $5.67.
Thursday, December 11, 2008
Qatar Future Natural Gas Associations
By Brian Habacivch, Senior Vice President, Fellon-McCord & Associates
Dec. 10, 2008 -- Located in the southern-middle portion of the Persian Gulf, Qatar has a population of less than 1.5 million but boasts the highest per capita income in the Arab world and is notably rich in oil and even richer in natural gas. With last month's announcement that Qatar is participating in a natural gas "troika" with Iran and Russia, this small Arab Emirate has increased its profile in the energy business and has caught the attention of large consumer nations that are its primary customers. The troika's announced intentions to hold quarterly meetings, sharing information about production schedules, investment plans, and prices, has kindled fears of a new OPEC in the global liquefied natural gas (LNG) business with possible negative implications for the West.
The potential for a new OPEC-like organization in the global natural gas trade to control prices is a hot topic of discussion in the energy industry. A quick review of OPEC's ability to control the global price of oil raises some questions as to the potential effectiveness of the newly announced natural gas troika to control LNG prices.
OPEC was formed in 1960. Its primary goal was to wrest oil producing assets from the post WWII financial, political, and territorial arrangements struck by the U.S., Great Britain, and Russia. Oil prices, adjusted for inflation, were flat to falling for the first eleven years of the cartel's existence. The oil embargo of 1973 and the Iranian revolution of 1978 led to two major oil-price shocks in the 1970s, with OPEC realizing a new and powerful role in the world's economy. Oil prices peaked in the early 1980s and then collapsed in 1986.
When OPEC did collectively flex its muscles in the 1970s it led to two things: Massive demand destruction in the U.S. (oil consumption fell from 21 to 16 million barrels per day from 1979 to 1985) and a large increase in non-OPEC oil production, both of which led to a price collapse that was long in duration. The experience of a sustained price decline in the global oil market greatly tempered the appetite of OPEC's larger senior members to use oil supply as an economic or political weapon.
Adjusted for inflation, the price of gasoline in the U.S. took 27 years to return to highs reached in 1980. This price history of oil and gasoline has brought many to question the real pricing power of OPEC in the global oil market. If OPEC truly controls the price of oil, then how does one explain the rather poor price performance of the commodity for relatively long periods of time? The answer to this question is somewhat complicated. OPEC can exert influence in the oil market, particularly during periods of rapidly increasing demand or when geopolitical events in the Middle East threaten supply. However, a thorough examination of oil price history draws one to conclude that OPEC is more influenced by the forces of global supply and demand than it is a commander of oil prices.
The gas troika countries (Russia, Qatar, Iran) represent an estimated 55 percent of global natural gas reserves. Their control of a very large unmonetized natural gas base positions the alliance as a substantial force in the marketplace. However, the gas troika is apt to find that -- like OPEC -- it is subject to macroeconomic forces far more than it is in control of them.
The formation of an LNG troika is nonetheless troubling from a geopolitical standpoint. Qatar's announcement that it was forming such an arrangement caught many energy analysts by surprise. Qatar deployed troops to the multinational forces led by the U.S. in the first Gulf War, Qatar's security interests are linked tightly with the U.S. and it has strong diplomatic and financial ties to the West. Given Iran's nuclear ambitions and Russia's use of energy as a weapon-of-intimidation in Eastern and Western Europe, Qatar's alliance with these countries has more than raised eyebrows within the EU and elsewhere.
Qatar's ostensible alignment with Russia and Iran is threatening in that Russia will use such to its advantage on the global energy stage. Russia has twice, in the past three years, cut off natural gas supplies to Europe during the winter as blatant leverage of its position as the primary supplier of this vital commodity to that market. Russia's invasion of the Republic of Georgia was predicated on controlling the oil pipelines of the Caucasus region and was a direct warning to Ukraine to think twice about its intention to join NATO. Russia bullied Shell Oil Co., into handing over a large portion of the assets that Shell had developed at Russia's Sakhalin LNG project and is in the process of repeating this performance with BP at another major oil and natural gas producing venture.
The natural gas troika may have a limited ability to control prices for sustained periods of time. Its effectiveness in raising prices above their natural equilibrium dictated by supply and demand will be tested and analyzed. The broader concern for the U.S., EU, and Asian consumers is the geopolitical shift on the part of Qatar that has taken place coupled with the desire and practice, on the part of Russia, to use energy as a political and economic weapon.
Brian Habacivch is Senior Vice President of Fellon-McCord & Associates which is an energy consulting and management company working with its clients' energy personnel to source the most economic and reliable energy supplies available. www.fellonmccord.com.
Dec. 10, 2008 -- Located in the southern-middle portion of the Persian Gulf, Qatar has a population of less than 1.5 million but boasts the highest per capita income in the Arab world and is notably rich in oil and even richer in natural gas. With last month's announcement that Qatar is participating in a natural gas "troika" with Iran and Russia, this small Arab Emirate has increased its profile in the energy business and has caught the attention of large consumer nations that are its primary customers. The troika's announced intentions to hold quarterly meetings, sharing information about production schedules, investment plans, and prices, has kindled fears of a new OPEC in the global liquefied natural gas (LNG) business with possible negative implications for the West.
The potential for a new OPEC-like organization in the global natural gas trade to control prices is a hot topic of discussion in the energy industry. A quick review of OPEC's ability to control the global price of oil raises some questions as to the potential effectiveness of the newly announced natural gas troika to control LNG prices.
OPEC was formed in 1960. Its primary goal was to wrest oil producing assets from the post WWII financial, political, and territorial arrangements struck by the U.S., Great Britain, and Russia. Oil prices, adjusted for inflation, were flat to falling for the first eleven years of the cartel's existence. The oil embargo of 1973 and the Iranian revolution of 1978 led to two major oil-price shocks in the 1970s, with OPEC realizing a new and powerful role in the world's economy. Oil prices peaked in the early 1980s and then collapsed in 1986.
When OPEC did collectively flex its muscles in the 1970s it led to two things: Massive demand destruction in the U.S. (oil consumption fell from 21 to 16 million barrels per day from 1979 to 1985) and a large increase in non-OPEC oil production, both of which led to a price collapse that was long in duration. The experience of a sustained price decline in the global oil market greatly tempered the appetite of OPEC's larger senior members to use oil supply as an economic or political weapon.
Adjusted for inflation, the price of gasoline in the U.S. took 27 years to return to highs reached in 1980. This price history of oil and gasoline has brought many to question the real pricing power of OPEC in the global oil market. If OPEC truly controls the price of oil, then how does one explain the rather poor price performance of the commodity for relatively long periods of time? The answer to this question is somewhat complicated. OPEC can exert influence in the oil market, particularly during periods of rapidly increasing demand or when geopolitical events in the Middle East threaten supply. However, a thorough examination of oil price history draws one to conclude that OPEC is more influenced by the forces of global supply and demand than it is a commander of oil prices.
The gas troika countries (Russia, Qatar, Iran) represent an estimated 55 percent of global natural gas reserves. Their control of a very large unmonetized natural gas base positions the alliance as a substantial force in the marketplace. However, the gas troika is apt to find that -- like OPEC -- it is subject to macroeconomic forces far more than it is in control of them.
The formation of an LNG troika is nonetheless troubling from a geopolitical standpoint. Qatar's announcement that it was forming such an arrangement caught many energy analysts by surprise. Qatar deployed troops to the multinational forces led by the U.S. in the first Gulf War, Qatar's security interests are linked tightly with the U.S. and it has strong diplomatic and financial ties to the West. Given Iran's nuclear ambitions and Russia's use of energy as a weapon-of-intimidation in Eastern and Western Europe, Qatar's alliance with these countries has more than raised eyebrows within the EU and elsewhere.
Qatar's ostensible alignment with Russia and Iran is threatening in that Russia will use such to its advantage on the global energy stage. Russia has twice, in the past three years, cut off natural gas supplies to Europe during the winter as blatant leverage of its position as the primary supplier of this vital commodity to that market. Russia's invasion of the Republic of Georgia was predicated on controlling the oil pipelines of the Caucasus region and was a direct warning to Ukraine to think twice about its intention to join NATO. Russia bullied Shell Oil Co., into handing over a large portion of the assets that Shell had developed at Russia's Sakhalin LNG project and is in the process of repeating this performance with BP at another major oil and natural gas producing venture.
The natural gas troika may have a limited ability to control prices for sustained periods of time. Its effectiveness in raising prices above their natural equilibrium dictated by supply and demand will be tested and analyzed. The broader concern for the U.S., EU, and Asian consumers is the geopolitical shift on the part of Qatar that has taken place coupled with the desire and practice, on the part of Russia, to use energy as a political and economic weapon.
Brian Habacivch is Senior Vice President of Fellon-McCord & Associates which is an energy consulting and management company working with its clients' energy personnel to source the most economic and reliable energy supplies available. www.fellonmccord.com.
Wednesday, December 10, 2008
2 More Natural Gas Producers in Haynesville Shale
Associated Press
By ALAN SAYRE , 12.09.08, 04:38 PM EST
Two energy companies said Tuesday that they have started producing natural gas from the Haynesville Shale in northwestern Louisiana, considered one of the largest domestic gas finds in years.
Houston-based Petrohawk Energy Corp. (nyse: HK - news - people ) said it had three wells now producing about 73 million cubic feet a day, while Dallas-based Exco Resources (nyse: XCO - news - people ) Inc. said it had one well producing 22.9 million cubic feet a day.
The Haynesville Shale is a formation that lies in parts of Texas, Oklahoma and Louisiana. Researchers say it could eventually produce 29 trillion to 39 trillion cubic feet of natural gas.
In four sales earlier this year, the state Mineral Board took in $221.8 million for mineral rights to state and local government land - most of that in the Haynesville Shale area.
However, with natural gas prices sliding this fall, interest tapered off during the November sale, which attracted only $3.5 million in winning. Of 55 Haynesville Shale tracts up for sale, only three received bids.
By ALAN SAYRE , 12.09.08, 04:38 PM EST
Two energy companies said Tuesday that they have started producing natural gas from the Haynesville Shale in northwestern Louisiana, considered one of the largest domestic gas finds in years.
Houston-based Petrohawk Energy Corp. (nyse: HK - news - people ) said it had three wells now producing about 73 million cubic feet a day, while Dallas-based Exco Resources (nyse: XCO - news - people ) Inc. said it had one well producing 22.9 million cubic feet a day.
The Haynesville Shale is a formation that lies in parts of Texas, Oklahoma and Louisiana. Researchers say it could eventually produce 29 trillion to 39 trillion cubic feet of natural gas.
In four sales earlier this year, the state Mineral Board took in $221.8 million for mineral rights to state and local government land - most of that in the Haynesville Shale area.
However, with natural gas prices sliding this fall, interest tapered off during the November sale, which attracted only $3.5 million in winning. Of 55 Haynesville Shale tracts up for sale, only three received bids.
Tuesday, December 9, 2008
Duncan Buys More Natural Gas Pipeline
Duncan Energy Partners LP has acquired interests in three midstream energy companies from a group led by Enterprise Products Partners LP in a cash-and-stock deal valued at $730 million.
As part of the agreement the Houston midstream energy services company purchased a 51 percent membership interest in Enterprise Texas Pipeline LLC; a 51 percent general partnership interest in Enterprise Intrastate LP; and a 66 percent general partnership interest in Enterprise GC LP.
Duncan Energy paid Houston-based Enterprise (NYSE: EPD) $280.5 million in cash and 37.3 million of Class B units valued at $449.5 million. Enterprise, a midstream energy services company, already owned 5.4 million Duncan Energy common units, and the deal means Enterprise now owns about 74 percent of Duncan Energy’s outstanding limited partner units.
The acquisition, when closed later this month, will give Duncan (NYSE: DEP) control over entities including more than 8,000 miles of natural gas pipelines, more than 1,000 miles of natural gas liquids pipelines, a leased natural gas storage facility and other assets. All of the assets are located in Texas.
Duncan Energy is managed by its general partner, DEP Holdings LLC, which is wholly-owned by Enterprise Products Partners.
As part of the agreement the Houston midstream energy services company purchased a 51 percent membership interest in Enterprise Texas Pipeline LLC; a 51 percent general partnership interest in Enterprise Intrastate LP; and a 66 percent general partnership interest in Enterprise GC LP.
Duncan Energy paid Houston-based Enterprise (NYSE: EPD) $280.5 million in cash and 37.3 million of Class B units valued at $449.5 million. Enterprise, a midstream energy services company, already owned 5.4 million Duncan Energy common units, and the deal means Enterprise now owns about 74 percent of Duncan Energy’s outstanding limited partner units.
The acquisition, when closed later this month, will give Duncan (NYSE: DEP) control over entities including more than 8,000 miles of natural gas pipelines, more than 1,000 miles of natural gas liquids pipelines, a leased natural gas storage facility and other assets. All of the assets are located in Texas.
Duncan Energy is managed by its general partner, DEP Holdings LLC, which is wholly-owned by Enterprise Products Partners.
Monday, December 8, 2008
Natural Gas Shale Fracturing Getting a Congressional Look
By MIKE LEE
mikelee@star-telegram.com
There’s a move in Congress to impose tighter regulations on a key process used to recover natural gas in the Barnett Shale.
Hydraulic fracturing uses a mix of water, sand and chemicals to create tiny cracks in the rock and release the gas. But it’s been under fire for years from environmentalists who question whether the chemicals are safe.
Barnett Shale drillers said they rely less on gels and other chemicals and more on "slick water" — a mixture of water, sand and surfactants that are similar to those in soap and make the water easier to pump.
Any chemicals they do use — more than 50 compounds are listed in Fort Worth’s records — are a tiny percentage of the millions of gallons used in each well and are largely flushed out of the ground, drillers say.
And many of those chemicals — like sodium bicarbonate, or ordinary baking soda — are benign.
But others are potentially deadly, and disclosure requirements are lax, environmentalists say. What’s more, even the small percentage used in wells amounts to thousands of gallons of potential contaminants, environmentalists say. Once the chemicals are used, they must be disposed of.
A bill by U.S. Rep. Diana DeGette, D-Colo., would require companies to disclose the drilling chemicals they use and would subject them to the federal Clean Water Act.
The stakes are high because gas drilling is beginning to push into neighborhoods, near parks and next to water reservoirs in Tarrant County.
"The challenge all communities face is trying to figure out what’s going into their air and water, what’s going into their soil," said Jennifer Goldman, a researcher with the Oil and Gas Accountability Project.
Industry officials worry, too.
"Once the regulations are in place, the cost of compliance with those regulations is going to impact everyone that uses the fracturing technology," said Ed Ireland, executive director of the Barnett Shale Energy Education Council.
The background
Hydraulic fracturing has been used since the 1940s but has become a big issue in the last 10 years.
The method made it feasible to recover natural gas from the Barnett Shale. But environmentalists have consistently questioned whether the process is safe.
In a typical "frac job," a dozen trucks carrying high-powered pumps cluster around a well. They blast a mix of water and chemicals into the ground for a couple of days, opening cracks in the surrounding rock. In most cases, the mix includes sand, plastic beads or other "proppants" to hold the cracks open while gas and oil escape.
In 2005, Congress exempted hydraulic fracturing from the Clean Water Act, which regulates most industries that affect streams or aquifers.
A study by the Environmental Protection Agency determined that hydraulic fracturing posed little risk to water. Environmentalists say that the study is flawed and that the exemption poses health risks.
The chemicals
Even though the EPA and state regulators don’t track drilling chemicals, companies still have to file paperwork with cities explaining what chemicals are being kept on site.
The Star-Telegram obtained material safety data sheets, or MSDSs, for 55 compounds from Fort Worth officials.
The list seems to bear out the industry’s contention that drillers use mostly slick water. But 35 out of 55 compounds contain chemicals that are classified as health hazards.
Biocides, used to control bacteria that might grow in the drilling mud or the fracturing fluid, can also kill insects and leave the soil sterile if improperly handled.
Three of the polymers used to thicken the fracturing fluid can cause cancer either by themselves or because they might contain traces of other carcinogens. Several compounds include ester alcohol, which can harm animals and aquatic life.
The health effects from other chemicals range from skin irritation to cancer. One chemical can cause "difficulty breathing, twitching, lung congestion, paralysis and coma."
Industry’s position
Drillers say there is virtually no risk of groundwater contamination.
Only about 0.5 percent of fracture fluid is made up of chemicals — the rest is water, said Dan Arthur, a consultant who has studied fracturing. And the wells are managed so that pressure drives the fluid out of the ground when the well is completed.
"Those fluids don’t want to go in the shallow groundwater, they want to go in the well bore," he said. "If you look at what are the opportunities for fluids to reach groundwater, it’s so minute I would call it indistinguishable from zero."
Fracture fluids in the Barnett Shale are stored in portable tanks once they’re removed from the well. In New Mexico and Colorado, the fluid is often stored in pits, where chemicals can evaporate into the air or seep into the ground.
"If they’re doing the operation properly, the majority of the water is coming back up, and that’s being treated the right way," said Stephanie Meadows, a spokeswoman for the American Petroleum Institute.
Potential exposure
A typical fracturing job requires up to 3 million gallons of water. If chemicals make up 0.5 percent of that, they represent 5,000 to 15,000 gallons. In theory, the chemicals can’t harm the environment because they’re pushed deep underground.
The Texas Railroad Commission requires oil and gas wells to be fitted with steel casing and concrete deep enough to protect groundwater from potential contamination.
And there are thousands of feet of rock between the Barnett Shale and any drinkable water.
One concrete application has been documented to fail, although it was in Ohio, where hydraulic fracturing wasn’t being used, Arthur said.
But environmentalists warn of the human element — surface spills, truck accidents and other mishaps. "Even under the best conditions, this can be dangerous," said Luke Metzger, director of Environment Texas, an advocacy group.
In Texas, most wastewater from oil and gas drilling is injected into disposal wells. In Parker County, there were two accidents at disposal wells during one week in October.
"Cleanup of spills and releases is often a big concern for folks because they can’t be certain that all the chemicals have been removed if the public agency doesn’t know what they are looking for," Goldman said.
The unknown
Fort Worth’s paperwork doesn’t reveal everything that’s being used.
Some of the chemicals are listed by general names, such as "petroleum distillates" or ester alcohol. Two chemicals are listed as "proprietary."
Most fracturing is done by specialty firms such as Halliburton, Schlumberger and BJ Services. They have defended keeping the chemicals they use private.
"We make a significant investment in developing effective fracturing fluid systems, and we are careful to protect the fruits of the company’s research and development efforts," Halliburton spokeswoman Cathy Mann said.
Those loose definitions can cover a lot of ground, said Theo Colburn, a chemistry professor who runs the nonprofit Endocrine Disruption Network and has researched the health effects of drilling chemicals.
"They’re beginning to obfuscate the issue even more by basically not specifying the specific chemical that’s in the product," she said.
There’s little oversight of the paperwork. Companies are not required to submit the MSDSs to the Occupational Safety and Health Administration. Drilling companies decide what to record on product sheets.
"What we do know about a lot of chemicals is that short-term exposure, certainly at high levels, can cause serious problems," Metzger said. "What we don’t know is what some of the long-term impacts are."
The key question is not necessarily what’s being used but how.
"What are the volumes, concentrations and combinations?" Goldman asked.
Among the chemicals on file with Fort Worth is sodium bicarbonate. Under normal circumstances, it’s safe enough to use as toothpaste.
Drilling companies use baking soda to remove cement from drilling mud.
But "for every 1 pound of sodium bicarbonate used to precipitate lime, the equivalent of 0.48 pounds of caustic soda remains as a byproduct," the MSDS says
Caustic soda is corrosive and can burn the eyes, skin and lungs on contact. It can also kill fish if it gets in water.
Suggestions
DeGette’s bill is not the first attempt to increase oversight of fracturing, but previous bills on the subject never made it out of committee. Supporters believe that the measure has a better chance of passing after U.S. Rep. Henry Waxman, D-Calif., becomes chairman of the House Energy Committee next year. Waxman has criticized the energy industry and held hearings on fracturing in 2007.
DeGette’s bill wouldn’t necessarily mean stringent regulations, said Kristofer Eisenla, DeGette’s communications director. "We think this is a well-established precedent. If you’re conducting operations that might threaten public health, the government should have some oversight."
Cities don’t necessarily want that responsibility. Fort Worth doesn’t have the staff to monitor and review the chemicals being used, said Susan Alanis, the city’s planning and development director.
The Texas Railroad Commission has a form for companies to list the chemicals they use in each well.
"There is no requirement for operators to report component materials," commission spokeswoman Ramona Nye said. "An example of what is listed in this section of the form would be 2,019 barrels SW" or slick water.
Colorado’s Oil and Gas Commission is considering rules to require companies to list the chemicals being used at each drilling site, how much of each was used and when.
The rules would restrict oil and gas operations within 300 feet of streams, within a quarter-mile of public water supplies, and around the habitat of bighorn sheep, mule deer, elk, eagles, hawks and other wildlife.
The rules would also require companies to provide information about proprietary chemicals to health and environmental officials in case of emergency.
mikelee@star-telegram.com
There’s a move in Congress to impose tighter regulations on a key process used to recover natural gas in the Barnett Shale.
Hydraulic fracturing uses a mix of water, sand and chemicals to create tiny cracks in the rock and release the gas. But it’s been under fire for years from environmentalists who question whether the chemicals are safe.
Barnett Shale drillers said they rely less on gels and other chemicals and more on "slick water" — a mixture of water, sand and surfactants that are similar to those in soap and make the water easier to pump.
Any chemicals they do use — more than 50 compounds are listed in Fort Worth’s records — are a tiny percentage of the millions of gallons used in each well and are largely flushed out of the ground, drillers say.
And many of those chemicals — like sodium bicarbonate, or ordinary baking soda — are benign.
But others are potentially deadly, and disclosure requirements are lax, environmentalists say. What’s more, even the small percentage used in wells amounts to thousands of gallons of potential contaminants, environmentalists say. Once the chemicals are used, they must be disposed of.
A bill by U.S. Rep. Diana DeGette, D-Colo., would require companies to disclose the drilling chemicals they use and would subject them to the federal Clean Water Act.
The stakes are high because gas drilling is beginning to push into neighborhoods, near parks and next to water reservoirs in Tarrant County.
"The challenge all communities face is trying to figure out what’s going into their air and water, what’s going into their soil," said Jennifer Goldman, a researcher with the Oil and Gas Accountability Project.
Industry officials worry, too.
"Once the regulations are in place, the cost of compliance with those regulations is going to impact everyone that uses the fracturing technology," said Ed Ireland, executive director of the Barnett Shale Energy Education Council.
The background
Hydraulic fracturing has been used since the 1940s but has become a big issue in the last 10 years.
The method made it feasible to recover natural gas from the Barnett Shale. But environmentalists have consistently questioned whether the process is safe.
In a typical "frac job," a dozen trucks carrying high-powered pumps cluster around a well. They blast a mix of water and chemicals into the ground for a couple of days, opening cracks in the surrounding rock. In most cases, the mix includes sand, plastic beads or other "proppants" to hold the cracks open while gas and oil escape.
In 2005, Congress exempted hydraulic fracturing from the Clean Water Act, which regulates most industries that affect streams or aquifers.
A study by the Environmental Protection Agency determined that hydraulic fracturing posed little risk to water. Environmentalists say that the study is flawed and that the exemption poses health risks.
The chemicals
Even though the EPA and state regulators don’t track drilling chemicals, companies still have to file paperwork with cities explaining what chemicals are being kept on site.
The Star-Telegram obtained material safety data sheets, or MSDSs, for 55 compounds from Fort Worth officials.
The list seems to bear out the industry’s contention that drillers use mostly slick water. But 35 out of 55 compounds contain chemicals that are classified as health hazards.
Biocides, used to control bacteria that might grow in the drilling mud or the fracturing fluid, can also kill insects and leave the soil sterile if improperly handled.
Three of the polymers used to thicken the fracturing fluid can cause cancer either by themselves or because they might contain traces of other carcinogens. Several compounds include ester alcohol, which can harm animals and aquatic life.
The health effects from other chemicals range from skin irritation to cancer. One chemical can cause "difficulty breathing, twitching, lung congestion, paralysis and coma."
Industry’s position
Drillers say there is virtually no risk of groundwater contamination.
Only about 0.5 percent of fracture fluid is made up of chemicals — the rest is water, said Dan Arthur, a consultant who has studied fracturing. And the wells are managed so that pressure drives the fluid out of the ground when the well is completed.
"Those fluids don’t want to go in the shallow groundwater, they want to go in the well bore," he said. "If you look at what are the opportunities for fluids to reach groundwater, it’s so minute I would call it indistinguishable from zero."
Fracture fluids in the Barnett Shale are stored in portable tanks once they’re removed from the well. In New Mexico and Colorado, the fluid is often stored in pits, where chemicals can evaporate into the air or seep into the ground.
"If they’re doing the operation properly, the majority of the water is coming back up, and that’s being treated the right way," said Stephanie Meadows, a spokeswoman for the American Petroleum Institute.
Potential exposure
A typical fracturing job requires up to 3 million gallons of water. If chemicals make up 0.5 percent of that, they represent 5,000 to 15,000 gallons. In theory, the chemicals can’t harm the environment because they’re pushed deep underground.
The Texas Railroad Commission requires oil and gas wells to be fitted with steel casing and concrete deep enough to protect groundwater from potential contamination.
And there are thousands of feet of rock between the Barnett Shale and any drinkable water.
One concrete application has been documented to fail, although it was in Ohio, where hydraulic fracturing wasn’t being used, Arthur said.
But environmentalists warn of the human element — surface spills, truck accidents and other mishaps. "Even under the best conditions, this can be dangerous," said Luke Metzger, director of Environment Texas, an advocacy group.
In Texas, most wastewater from oil and gas drilling is injected into disposal wells. In Parker County, there were two accidents at disposal wells during one week in October.
"Cleanup of spills and releases is often a big concern for folks because they can’t be certain that all the chemicals have been removed if the public agency doesn’t know what they are looking for," Goldman said.
The unknown
Fort Worth’s paperwork doesn’t reveal everything that’s being used.
Some of the chemicals are listed by general names, such as "petroleum distillates" or ester alcohol. Two chemicals are listed as "proprietary."
Most fracturing is done by specialty firms such as Halliburton, Schlumberger and BJ Services. They have defended keeping the chemicals they use private.
"We make a significant investment in developing effective fracturing fluid systems, and we are careful to protect the fruits of the company’s research and development efforts," Halliburton spokeswoman Cathy Mann said.
Those loose definitions can cover a lot of ground, said Theo Colburn, a chemistry professor who runs the nonprofit Endocrine Disruption Network and has researched the health effects of drilling chemicals.
"They’re beginning to obfuscate the issue even more by basically not specifying the specific chemical that’s in the product," she said.
There’s little oversight of the paperwork. Companies are not required to submit the MSDSs to the Occupational Safety and Health Administration. Drilling companies decide what to record on product sheets.
"What we do know about a lot of chemicals is that short-term exposure, certainly at high levels, can cause serious problems," Metzger said. "What we don’t know is what some of the long-term impacts are."
The key question is not necessarily what’s being used but how.
"What are the volumes, concentrations and combinations?" Goldman asked.
Among the chemicals on file with Fort Worth is sodium bicarbonate. Under normal circumstances, it’s safe enough to use as toothpaste.
Drilling companies use baking soda to remove cement from drilling mud.
But "for every 1 pound of sodium bicarbonate used to precipitate lime, the equivalent of 0.48 pounds of caustic soda remains as a byproduct," the MSDS says
Caustic soda is corrosive and can burn the eyes, skin and lungs on contact. It can also kill fish if it gets in water.
Suggestions
DeGette’s bill is not the first attempt to increase oversight of fracturing, but previous bills on the subject never made it out of committee. Supporters believe that the measure has a better chance of passing after U.S. Rep. Henry Waxman, D-Calif., becomes chairman of the House Energy Committee next year. Waxman has criticized the energy industry and held hearings on fracturing in 2007.
DeGette’s bill wouldn’t necessarily mean stringent regulations, said Kristofer Eisenla, DeGette’s communications director. "We think this is a well-established precedent. If you’re conducting operations that might threaten public health, the government should have some oversight."
Cities don’t necessarily want that responsibility. Fort Worth doesn’t have the staff to monitor and review the chemicals being used, said Susan Alanis, the city’s planning and development director.
The Texas Railroad Commission has a form for companies to list the chemicals they use in each well.
"There is no requirement for operators to report component materials," commission spokeswoman Ramona Nye said. "An example of what is listed in this section of the form would be 2,019 barrels SW" or slick water.
Colorado’s Oil and Gas Commission is considering rules to require companies to list the chemicals being used at each drilling site, how much of each was used and when.
The rules would restrict oil and gas operations within 300 feet of streams, within a quarter-mile of public water supplies, and around the habitat of bighorn sheep, mule deer, elk, eagles, hawks and other wildlife.
The rules would also require companies to provide information about proprietary chemicals to health and environmental officials in case of emergency.
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