Monday, Jun. 16, 2003. Page 6 The Moscow Times, Reuters

Gazprom said last week it would set up a world-scale oil trading branch whose first task would be to take over part of Iran's gas condensate operations from French Total.

Gazprom, the world's largest gas producer, said in a statement that its main export arm, Gazexport, would set up an office in Iran to market the gas condensate that Gazprom is getting from its production-sharing agreement with the state.

Gazprom, Total and Malaysian Petronas signed an agreement in 1997 to develop phases two and three of Iran's South Pars offshore Persian Gulf field, one of the biggest in the world with reserves of above 12 trillion cubic meters.

The field also contains around 600 million metric tons of gas condensate that will be sold on international markets to compensate international firms for their investments in the field.

Gazprom, which supplies Europe with one-fourth of its gas needs, had initially wanted Total, which is leading phases two and three with 40 percent, to market its share of gas condensate exports, but said Wednesday it now wanted to expand into the trading business itself.

"Entering the global oil liquid market will allow Gazprom to gain experience in international trading and create opportunities to boost these activities based on our projects to produce liquids in Russia, Iran, Vietnam, Pakistan, Algeria and Venezuela," the statement said.

Gazprom produces around 200,000 barrels per day of oil and gas condensate in Russia on top of its giant gas production of about 530 billion cubic meters a year.

Gazexport has recently hired several traders from Nafta Moskva, the biggest Russian oil trader in the mid-1990s, whose operation has shrunk virtually to zero over the last few years as domestic oil majors have squeezed out independent trading firms.

Market analysts have praised Gazprom's decision to consolidate oil trading under the branch of Gazexport, saying it could help the company boost revenues to service its huge debt and invest billions of dollars to maintain gas output.

 Spot sales of Russian gas to Europe are increasing in a trend that will boost the continent's trading market, an expert on Russian gas said last week.

Most Russian gas sales to Europe are still on long term contracts and only around 1.2 billion cubic meters of the total 130 bcm were sold in short-term deals.

But spot sales to countries such as Britain and Belgium were rising, said Jonathan Stern, director of natural gas research at Britain's Oxford Institute for Energy Studies.

"The role for short term trading [of Russian gas] is still small but increasing and it will add to the potential of the trading market in Europe," he said on the sidelines of an energy trading conference in Berlin.

Spot gas trading in Europe is gathering pace as the European Union opens up its energy markets to full competition.

Gazprom said in November it that planned to boost spot sales to Britain and Belgium.

The announcement came after the company booked extra capacity in the Interconnector pipeline linking Britain with Zeebrugge in Belgium, mainland Europe's main gas trading hub.

Gazprom owns a 10 percent share in the Interconnector and has trading offices in London.

Tue June 10, 2003 06:46 PM ET By Chris Baltimore

WASHINGTON (<a href=reuters.com>Reuters) - Federal Reserve Chairman Alan Greenspan said Tuesday shrinking supplies of U.S. natural gas mean the nation must build more gas import terminals to create a "safety valve" that will help stabilize prices.

An unusually low stockpile of natural gas has grabbed the attention of the Bush administration and lawmakers. Greenspan, who usually appears on Capitol Hill to discuss broad economic trends, was asked to testify at the House Energy and Commerce Committee on the impact of high gas prices.

Natural gas costs $6 per one million British thermal units (Btu) in the spot market, double the level of one year ago.

If natural gas prices remain high, Greenspan said there eventually could be "some erosion" in the U.S. economy.

While energy industry experts urged the panel to open more federal lands to drilling, Greenspan focused on the role that liquefied natural gas (LNG) imports could play.

LNG is "a crucial safety valve in maintaining price stability in oil, and it could be in gas as well," he said.

LNG is natural gas cooled to minus 259 degrees Fahrenheit, which converts it to a liquid for shipment. After arriving at a terminal, it is converted into dry gas for conventional uses.

"Access to world natural gas supplies will require a major expansion of LNG terminal import capacity," he said. "Without the flexibility such facilities will impart, imbalances in supply and demand must inevitably engender price volatility."

Building new U.S. LNG terminals often faces resistance from environmental groups concerned about the potential for an explosive accident or sabotage of an LNG tanker.

Several LNG projects have been proposed in recent months, including the expansion of Georgia's Elba Island terminal and new facilities off Louisiana, Texas, California, the Bahamas and Mexico. LNG terminals now exist in Cove Point, Maryland, Everett Massachusetts and Lake Charles, Louisiana.

ChevronTexaco Corp. CVX.N , ConocoPhillips COP.N , Marathon Oil Corp. MRO.N , and Exxon Mobil Corp. XOM.N have announced plans to make LNG a bigger part of future operations.

Algeria, Nigeria, Trinidad, Russia and Venezuela are among the potential exporters of LNG to the U.S. market.

Earlier, energy industry executives urged the House panel to ease gas supplies by lifting drilling restrictions on federal lands in the Rocky Mountains and some offshore areas.

Greenspan sidestepped the politically volatile issue, saying he could not judge the environmental trade-offs.

"I'm an economist. My view is if you're looking for natural gas you've got to know whether it's there," he said. "The only way to find out is to drill a hole."

U.S. gas supplies are 29 percent below the five-year average. Demand has soared as consumers and industry find more uses for gas.

"We see a storm brewing on the horizon and we need to prepare for it," said committee chairman Rep. Billy Tauzin, a Louisiana Republican. "Drilling companies are at work everywhere they are allowed to go," he said, but "vast areas of land" are off-limits in the Rocky Mountains and offshore.

In the Senate, which is debating a broad energy bill this week, a fight looms over a Republican demand for an inventory of natural gas deposits in the Outer Continental Shelf -- including Florida and California, where drilling is banned.

Environmental groups contend plenty of land is already available, and restricted areas protect fragile habitats and national parks. The Interior Department reported two-thirds of 59 million acres of federal land in Colorado, Utah, Wyoming, Montana and New Mexico were available for drilling.

Guy Caruso, head of the U.S. Energy Information Administration, said gas supplies should be adequate this summer if temperatures are in the normal range. Prices are forecast at $5 to $6 per million Btu this year, and longer term are likely to fall to $3 to $4 per million Btu, he said.

Demand for natural gas is forecast to top 35 trillion cubic feet (Tcf) by 2025, a jump of 52 percent from this year. If the drilling ban in offshore waters was lifted, an extra 58 Tcf of gas could be produced, Caruso said. Ending restrictions in the Rocky Mountains would add an estimated 70 Tcf of gas, he said.

Knight Ridder - Thursday, June 05, 2003 <a href=www.menafn.com>The Dallas Morning News By Brendan M. Case

ALTAMIRA, Mexico _ Bountiful natural gas deposits lie just a few hundred miles from this bustling port city on Mexico's Gulf Coast. But officials here are planning to import boatloads of gas from as far away as Africa.

The Federal Electricity Commission _ or CFE _ plans to hire a major energy company this year to build a liquefied natural gas terminal and re-gasification plant in Altamira.

The natural gas, or LNG, project, with a price of about $500 million, would fuel a complex of power plants in this burgeoning region some 300 miles south of Texas.

"This area is seeing a lot of economic growth, and we need more electricity," said Arnoldo Garcia Gonzalez, who oversees the CFE's operations here. "To generate electricity, we need natural gas."

The LNG rush reflects Mexico's increasingly urgent efforts to shore up its natural gas supply. State-owned oil monopoly Petroleos Mexicanos, or Pemex, has neglected gas production for years. Now, however, authorities are promoting the clean-burning fuel in power plants, factories and homes _ and demand is booming.

Altamira probably will get the first of several LNG projects south of the border. Texas companies and global competitors also are planning LNG projects in Baja California, which would supply customers in both Mexico and the United States.

Skeptics say Mexico should develop its own natural gas reserves instead of relying on imports. But investment remains limited. Pemex channels most spending to oil production, and Mexico prohibits private companies from developing oil and gas reserves.

"We're a country that could export gas and make a big industry out of exploring for and producing gas," said Hector Rangel Domene, president of the Business Coordinating Council, a leading private-sector lobbying group in Mexico City. "It's absurd that we can't do that."

Mexico has already become a juicy market for Texas gas exporters. Three months ago, Houston-based Kinder Morgan Inc. opened an $87 million cross-border pipeline. Tidelands Oil & Gas Corp., a Corpus Christi, Texas, company, sold its gas production business last year to build cross-border pipelines.

Within a few years, Mexico might also be welcoming ships laden with supercooled LNG from Nigeria, Venezuela, Malaysia or Indonesia.

"There's a growing gas market in Mexico," said Barbara Blakely, a spokeswoman for Shell Mexico, which hopes to win the LNG contract in Altamira and to build a separate plant in Baja California. "Moving gas from one part of the world to another is no longer uncommon. We do it all the time."

Mexico still is a major crude oil exporter. But the country's growing appetite for gas imports illustrates its growing industrialization.

Glass and steel companies are devouring natural gas. More important, demand for electricity is rising quickly _ and gas-fired power plants are getting the most new investment.

Recent legal changes have created a whole new business for natural gas distribution companies. Millions of consumers are now burning natural gas in their homes instead of liquid petroleum gas, the traditional fuel.

All told, natural gas imports reached nearly 650 million cubic feet per day during the first three months of the year, nearly three times what they were in 2000, according to Pemex. Domestic gas production has failed to keep pace with demand.

"Productive capacity is not increasing, while demand is rising quickly," said Alejandro Gonzalez, an analyst with Cambridge Energy Research Associates, in Cambridge, Mass. "The United States is in the same situation."

Pemex is trying to lure private companies to help develop gas reserves in northern Mexico's Burgos basin, a project that would cost at least $6 billion. But that plan faces political opposition from critics who say it violates Mexico's strict limits on private energy investment.

So the search is on for other gas sources, including LNG. Within a few years, LNG could conceivably account for more than 1 billion cubic feet per day _ about as much as Pemex hopes private companies would extract from Burgos.

"If you start a new program to drill natural gas, how much is it going to cost you? Ten billion dollars?" asked Gonzalez. "If you build an LNG terminal, it will cost you half a billion dollars. And you'll get the gas as soon as the terminal is finished."

Many LNG projects face stiff political opposition.

In Baja California, business leaders and grassroots activists have warned that LNG terminals would create eyesores and security risks in areas that depend on tourism. Opponents fret that such terminals might prove tempting targets for terrorists.

Mexican officials say LNG plants would be built with an eye to security concerns. Blakely, the Shell spokeswoman, says her company has never experienced a major accident with LNG.

Other critics worry that energy companies will turn Mexico into a huge LNG depot for the United States, selling gas to U.S. customers while taking advantage of weaker environmental enforcement south of the border.

"Mexico could turn into a big LNG platform for the United States," said Victor Rodriguez-Padilla, an energy expert who advises the opposition Institutional Revolutionary Party. "One of the risks is that our environmental standards would be ignored."

Energy companies say they still hope to build LNG projects in Baja California, with plans to sell gas to customers on both sides of the border. Backers include the Royal Dutch/Shell Group; Houston-based ConocoPhillips; Houston-based Marathon Oil Corp., ChevronTexaco Corp., which is based in San Ramon, Calif.; and Sempra Energy, which hails from San Diego.

Analysts say Baja California could probably only support one or two such projects, adding that it's hard to tell which company is winning the race to obtain all necessary permits.

In May, however, Mexican authorities issued Baja California's first LNG permit to Marathon Oil. Marathon executives envision a $1.5 billion "Tijuana Regional Energy Center," which would include LNG facilities, a power plant and a desalination plant to provide fresh water.

"The Tijuana area is seeing tremendous growth," said Paul Weeditz, a spokesman for Marathon. "Without these basic infrastructure elements, developing the economy is tough to achieve."

The Altamira LNG project could be the first to move forward.

Unlike the Baja projects, which would seek their own customers, the Altamira terminal would sell its gas to the Federal Electricity Commission, the CFE. The CFE would burn the gas in several power plants providing much-needed electricity to the national grid.

Companies such as Mexico's Petrocel-Temex, Germany's BASF AG and U.S.-based General Electric Co. have major plastics and petrochemical plants in Altamira. Local power plants also can transmit power to customers in Monterrey, the northern business capital, and elsewhere in Mexico.

Altamira's LNG plant would need to supply up to 500 million cubic feet of gas per day. The price would be tied to Henry Hub benchmark prices on the New York Mercantile Exchange. At current prices, which are historically high, 500 million cubic feet of gas is worth nearly $3 million.

CFE officials originally had said they would announce the winner in April. Now they say a winner could be announced this summer. Officials said in January that companies interested in the project included Shell, BP, Spain's Iberdrola and other major competitors.

Would-be suppliers would have to show that the total price Mexico pays for LNG would be less than what it would pay to import gas through a pipeline. The CFE would agree to buy the gas for 15 years.

"This area is going to be one of the most important power generation areas in the country," said Garcia, the local CFE director in the Tampico-Altamira area. "With all the new development in gas and electricity, we'll be able to satisfy demand."

05/14/2003 By BRENDAN M. CASE / The Dallas Morning News

ALTAMIRA, Mexico – Bountiful natural gas deposits lie just a few hundred miles from this bustling port city on Mexico's Gulf Coast. But officials here are planning to import boatloads of gas from as far away as Africa.

The Federal Electricity Commission – or CFE – plans to hire a major energy company this year to build a liquefied natural gas terminal and re-gasification plant in Altamira.

The LNG project, with a price of about $500 million, would fuel a complex of power plants in this burgeoning region about 300 miles south of Texas.

"This area is seeing a lot of economic growth, and we need more electricity," said Arnoldo García González, who oversees the CFE's operations here. "To generate electricity, we need natural gas."

The LNG rush reflects Mexico's increasingly urgent efforts to shore up its natural gas supply. State-owned oil monopoly Petróleos Mexicanos, or Pemex, has neglected gas production for years. Now, however, authorities are promoting the clean-burning fuel in power plants, factories and homes – and demand is booming.

Altamira probably will get the first of several LNG projects south of the border. Texas companies and global competitors also are planning LNG projects in Baja California, which would supply customers in both Mexico and the United States.

Skeptics say Mexico should develop its own natural gas reserves instead of relying on imports. But investment remains limited. Pemex channels most spending to oil production, and Mexico prohibits private companies from developing oil and gas reserves.

"We're a country that could export gas and make a big industry out of exploring for and producing gas," said Héctor Rangel Domene, president of the Business Coordinating Council, a leading private-sector lobbying group in Mexico City. "It's absurd that we can't do that."

Mexico has already become a juicy market for Texas gas exporters. Two months ago, Houston-based Kinder Morgan Inc. opened an $87 million cross-border pipeline. Tidelands Oil & Gas Corp., a Corpus Christi company, sold its gas production business last year to build cross-border pipelines.

Within a few years, Mexico might also be welcoming ships laden with super-cooled LNG from Nigeria, Venezuela, Malaysia or Indonesia.

"There's a growing gas market in Mexico," said Barbara Blakely, a spokeswoman for Shell México, which hopes to win the LNG contract in Altamira and to build a separate plant in Baja California. "Moving gas from one part of the world to another is no longer uncommon. We do it all the time."

Appetite for imports

Mexico still is a major crude oil exporter. But the country's growing appetite for gas imports illustrates its growing industrialization.

Glass and steel companies are devouring natural gas. More important, demand for electricity is rising quickly – and gas-fired power plants are getting most new investment. Recent legal changes have created a whole new business for natural gas distribution companies. Millions of consumers are now burning natural gas in their homes instead of liquid petroleum gas, the traditional fuel.

All told, natural gas imports reached nearly 650 million cubic feet per day during the first three months of the year, nearly three times what they were in 2000, according to Pemex. Domestic gas production has failed to keep pace with demand.

"Productive capacity is not increasing, while demand is rising quickly," said Alejandro González, an analyst with Cambridge Energy Research Associates in Cambridge, Mass. "The United States is in the same situation."

Pemex is trying to lure private companies to help develop gas reserves in northern Mexico's Burgos basin, a project that would cost at least $6 billion. But it faces political opposition from critics who say it violates Mexico's strict limits on private energy investment.

So the search is on for other gas sources, including LNG. Within a few years, LNG could conceivably account for more than one billion cubic feet per day – about as much as Pemex hopes private companies would extract from Burgos.

"If you start a new program to drill natural gas, how much is it going to cost you? Ten billion dollars?" asked Mr. González. "If you build an LNG terminal, it will cost you half a billion dollars. And you'll get the gas as soon as the terminal is finished."

Many LNG projects face stiff political opposition.

In Baja California, business leaders and grass-roots activists have warned that LNG terminals would create eyesores and security risks in areas that depend on tourism. Opponents fret that such terminals might prove tempting targets for terrorists.

Mexican officials say LNG plants would be built with an eye to security concerns. Ms. Blakely, the Shell spokeswoman, says her company has never experienced a major accident with LNG.

Other critics worry that energy companies will turn Mexico into a huge LNG depot for the United States, selling gas to U.S. customers while taking advantage of weaker environmental enforcement south of the border.

"Mexico could turn into a big LNG platform for the United States," said Víctor Rodríguez-Padilla, an energy expert who advises the opposition Institutional Revolutionary Party. "One of the risks is that our environmental standards would be ignored."

Baja California's role

Energy companies say they still hope to build LNG projects in Baja California, with plans to sell gas to customers on both sides of the border. Backers include Royal Dutch/Shell Group; Houston-based ConocoPhillips; Houston-based Marathon Oil Corp., ChevronTexaco Corp., which is based in San Ramon, Calif.; and Sempra Energy, which hails from San Diego.

Analysts say Baja California could only support one or two such projects, adding that it's hard to tell which company is winning the race to obtain all necessary permits. Last week, however, Mexican authorities issued Baja California's first LNG permit to Marathon Oil. Marathon executives envision a $1.5 billion "Tijuana Regional Energy Center," which would include LNG facilities, a power plant and a desalination plant to provide fresh water.

"The Tijuana area is seeing tremendous growth," said Paul Weeditz, a spokesman for Marathon. "Without these basic infrastructure elements, developing the economy is tough to achieve."

Hopes for Altamira

The Altamira LNG project could be the first to move forward.

Unlike the Baja projects, which would seek their own customers, the Altamira terminal would sell its gas to the Federal Electricity Commission, the CFE. The CFE would burn the gas in several power plants providing much needed electricity to the national grid.

Companies such as Mexico's Petrocel-Temex, Germany's BASF AG and U.S.-based General Electric Co. have major plastics and petrochemical plants in Altamira. Local power plants also can transmit power to customers in Monterrey, the northern business capital, and elsewhere in Mexico.

Altamira's LNG plant would need to supply up to 500 million cubic feet of gas a day. The price would be tied to Henry Hub benchmark prices on the New York Mercantile Exchange. At current prices, which are historically high, 500 million cubic feet of gas is worth nearly $3 million.

CFE officials originally had said they would announce the winner in April. Now they say a winner could be announced this summer. Officials said in January that companies interested in the project included Shell, BP, Spain's Iberdrola and other major competitors.

Would-be suppliers would have to show that the total price Mexico pays for LNG would be less than what it would pay to import gas through a pipeline. The CFE would agree to buy the gas for 15 years.

"This area is going to be one of the most important power generation areas in the country," said Mr. García, the local CFE director in the Tampico-Altamira area. "With all the new development in gas and electricity, we'll be able to satisfy demand."

Research librarian Darlean Spangenberger contributed to this report.

E-mail bcase@dallasnews.com

<a href=ogj.pennnet.com>Oil & Gas Journal By an OGJ correspondent

RIO DE JANEIRO, Apr. 28 -- At a meeting Monday, Brazilian President Luiz Inácio Lula da Silva failed to convince Bolivia's President Gonzalo Sánchez de Lozada to revise the contract under which Brazil imports a fixed quota of gas from its neighbor.

"It is very unlikely that Bolivia will distance itself from what was agreed (with Brazil) in good faith in the past. It is unlikely that we will change the take-or-pay clause of the contract," said Lozada.

However, Brazilian Energy Minister Dilma Rousseff, who also took part in the talks, declared, "Brazil will only increase the volume of gas imported from Bolivia if the price of the fuel is reduced."

Brazil wanted to revise the take-or-pay clause in the import contract signed with Bolivia in 1996. Under that agreement, Brazil pays for a certain quota of imported Bolivian gas even if it does not need to import the fuel. Brazilian officials claim the take-or-pay provision will cost Brazil more than the present $150 million/year.

The minimum gas quota Brazil agreed to import from Bolivia is 14 million cu m/d. Under the agreement, the minimum quota would be boosted to 18 million cu m/d by 2004.

However, Brazil currently demands only 11 million cu m/d.The Brazilian economy is undergoing a severe recession, and it is unlikely that Brazil's gas consumption will increase from present levels for at least the next 2 years, said local analysts. Moreover, Lula's administration shelved the ambitious gas fired thermoelectric plants project devised by former President Fernando Henrique Cardoso.

Brazilian officials said the price of imported Bolivian gas has dampened Brazil's demand for the commodity. However, Lozada rejected the possibility of reducing gas prices without Brazil increasing imports.

A source in Brazil's foreign ministry told OGJ Online that he was not surprised with Lozada's position since Bolivia's president heads one of Latin America's most nationalistic and poorest countries.

Bolivia's natural gas reserves are estimated at 52 tcf, second in Latin America behind Venezuela. Bolivia's economy depends heavily on its gas sales, the source said. In addition, Losada faces strong opposition from powerful left wing factions in Bolivia who oppose lowering prices of exported gas.