sept 05 update

BHP Billiton, Australia's largest oil and gas company, said as of the first week of September, most of its 25,000 barrels-a-day of production in the Gulf of Mexico has restarted after disruptions caused by Hurricane Katrina.

All fields have resumed production apart from the BHP- operated Boris and the BP Plc-operated Mad Dog fields, said Emma Meade, a spokeswoman for the Melbourne-based company.

BHP Billiton, which is also the world's largest miner, also has stakes in the Chevron Corp.-operated Typhoon and Genesis fields, and in the West Cameron 76 and Green Canyon 18 projects. Crude oil futures in New York reached a record $70.85 a barrel on Aug. 30 after Hurricane Katrina closed down platforms and refineries in the Gulf.

``All fields are in production except for Boris and Mad Dog, and teams are working to get them back online as soon as possible,'' Meade said in an interview. There are no reports of any damage to those projects, or to the $2.5 billion Atlantis oil project which is due to start production next year, she said.

BHP Billiton produced 119 million barrels of oil equivalent in the year ended June 30, and its oil and gas unit accounts for about 20 percent of earnings before interest and tax. It also owns minority stakes in the Caesar oil pipeline and the Cleopatra gas pipelines in the Southern Green Canyon area which transport petroleum from Mad Dog and Atlantis, and from BP's Holstein field.

The West Cameron project continued to produce as normal throughout, Merrill Lynch & Co. said in a Sept. 7 report.

Katrina Update for ATP Oil & Gas

ATP Oil & Gas Corp. said it has restored production at all but seven of its Gulf of Mexico properties impacted by Hurricane Katrina, bringing output to more than 80 percent of pre-hurricane levels. The company said it expects to restore the remaining production during the remainder of the year. ATP estimates it will defer about one billion cubic feet of natural gas equivalent of production from the third quarter to future periods.

Remington Oil and Gas Corporation Provides Operations Update

Remington Oil and Gas Corporation, in a presentation September 8, updated investors on current and future drilling and production operations discussed below in this press release.

The Company estimated 65 percent of its pre-storm production has been restored. The Company expects production to resume at its largest producing field, East Cameron 346, next week following a two week shut down due to a facility upgrade and Hurricane Katrina. At the Company's non-operated South Pass 89 Complex, damage to three production platforms varies from minor to severe. Estimates for production restoration at this complex range from weeks to months. This field, prior to the storm, represented approximately 5 percent of our daily production. Remington will update its 3rd and 4th quarter production guidance as soon as it can more fully evaluate the final impact of the storm.

Fellows Energy Ltd. to Purchase Producing Gas Field in Utah

Fellows Energy Ltd. (OTCBB:FLWE) ("Fellows") announced September 12 that it has entered into an agreement to purchase a producing gas field in Carbon County, Utah. The field comprises 5,953 gross acres (4,879 net acres) with three gas wells currently producing approximately 30 million cubic feet of natural gas per month. Production is derived from the Ferron Sandstone formation. The gas is marketed into the adjacent gas pipeline operated by Questar Gas Resources. The field has potential for 20 additional well sites on 160 acre spacing on the undeveloped acreage. The property is adjacent to Fellows' Gordon Creek project and to the very successful Drunkards Wash field originally developed by River Gas Corp.

Fellows will use the experience of its personnel who participated in the development of Drunkards Wash to increase current production and expand production in both the Ferron Sandstone and in the underlying coal bed methane seams that are not currently being exploited by the existing wells. The coal seams include some of the same seams that have been prolific in the Drunkards Wash field. Fellows will immediately undertake to increase production in the existing wells, complete those wells in the coal for their coal bed methane potential, and thereafter drill additional wells on the acreage being acquired.

Terms of the purchase agreement have been held confidential pending closing, scheduled for on or before November 1, 2005. Engineering and reserve studies are currently underway.

"The purchase represents an excellent strategic opportunity in a proven area and will provide immediate production and cash flow," said Fellows President George Young. "We believe we can increase current production and achieve production on the surrounding acreage to generate additional cash flow for the Company. This new project will compliment the interests in over 500,000 acres of exploration projects we already have, and will help propel us forward with our business plans."

The announcement follows recent arrangements to option the Platte and Badger projects, two new shallow gas projects developed by Thomasson Partner Associates, Inc. of Denver, Colorado. Those projects result from years of study and analysis by the professional geologists at Thomasson. Other recent announcements include the restructuring of a joint venture with JMG Exploration, Inc. on the Weston County and Gordon Creek projects and the acquisition of an interest in the Kirby and Castle Rock projects in the Powder River Basin.

Oil Production in Gulf still nearly 60% Blocked

More than 120 Gulf of Mexico oil and gas platforms were still shut down September 10 and nearly 60 percent of the Gulf's normal daily oil production remained blocked from the market because of evacuations due to Hurricane Katrina, a federal agency said.

After a survey of 56 energy companies, the Minerals Management Service reported that 122 of the 819 staffed platforms in the Gulf were shut down, blocking 897,605 barrels -- or 59.8 percent of the Gulf's normal daily production of 1.5 million barrels.

The shutdowns also blocked 3.8 billion barrels of natural gas from the market, or 38.2 percent of the Gulf's normal daily gas production of 10 billion cubic feet, the agency said.

Since Katrina first threatened the Gulf on Aug. 26, 17.1 million barrels of oil and 84.2 billion cubic feet of gas have been shut in, the agency said. Normally, the Gulf of Mexico produces 547.5 million barrels of oil and 3.65 trillion cubic feet of gas annually.

On September 9, light, sweet crude for October delivery fell 41 cents to settle at $64.08, after reaching as high as $65.35 and as low as $63.55 on the New York Mercantile Exchange.

Eni’s Houston Affiliate Buys Armstrong’s North Slope Assets

Eni Petroleum Exploration Co. has purchased the assets of Armstrong Alaska, which include 104 oil and gas leases on the North Slope where Eni said “reserves are expected to exceed 170 million barrels.” The leases encompass 341,500 gross (273,000 net) acres onshore and offshore in state and federal waters (see map). As part of the deal Eni will inherit Armstrong’s minority working interests with Pioneer Natural Resources and Kerr-McGee in northern Alaska, including the proposed Oooguruk and Nikaitchuq developments.

An affiliate of Italy’s Eni SpA, Houston-based Eni Petroleum told Petroleum News that it considers the “North Slope and Beaufort Sea as areas with exploration potential for new finds” and said Eni has “decided to establish a position in the area with an emphasis of consistent growth.”

The company said it is “always looking for opportunities to further enhance its competitive presence in the areas where it operates. Alaska is no exception and Eni will consider all opportunities available, and continue to invest in regional studies to assess the potential of new areas, with special attention to the Beaufort and Chukchi sea areas.”

Eni said that it is “evaluating” whether or not to set up an office in Alaska. The company has not yet selected a person to oversee its Alaska assets, but said if an Alaska coordinator is named that person would report to Eni Petroleum’s Houston office which “manages E&P operations in (the) Gulf of Mexico and will also manage the operations in Alaska.”

Although Armstrong was the first company to cut a deal with Eni in Alaska, Eni made its decision to enter Alaska “based on its internal studies and evaluation, while keeping a close eye on all the available opportunities. In addition, Eni intends to leverage the experience gained from its operatorship in other challenging areas such as Kazakhstan, where there are similar requirements for high levels of technology, as well as analogous operating conditions.”

Eni’s comparison of Alaska to Kazakhstan could bode well for Alaska. Eni operates Kazakhstan’s huge Kashagan field in the Caspian Sea. Since it entered Kazakhstan in 1992 (10 months after the country’s independence from the former Soviet Union), Eni has made itself part of the new nation’s future. Among other things, Eni undertook the expense of training some of Kazakhstan’s new oil ministry employees at its headquarters in Italy and it funded the construction of the Kazakh national library.

When asked if Eni plans to be an operator in Alaska, the company said it operates in other Arctic areas, and “generally takes a leadership role in its joint ventures worldwide.”

Initially, Eni said it “intends to fully cooperate with its partners who operate some projects in the pre-development stage. It is Eni’s intention to bring its experience onboard while taking the time to understand the peculiarity and challenges of the area.” The company has not yet decided whether it will drill any of its 100 percent-owned acreage this coming winter: “It is too early to comment. This will be evaluated during our 2006 budget and planning process.”

Although Eni said it will evaluate the possibility of partnering with Shell on Shell’s planned Beaufort Sea seismic shoot for next summer, no decision will be made until Eni has completed its 2006 budget and planning process.

In Alaska, “as in all of its activities”, Eni said it is fully committed to sustainable development and environmental protection of the areas in which it operates. In the Gulf of Mexico, Eni has received several nominations for Safety Awards from the Minerals Management Service.

ONEOK Sells Its Oil and Gas Production Companies

ONEOK, Inc. has signed an agreement with TXOK Acquisition, Inc. to purchase ONEOK's oil and gas production companies for $645 million. The transaction is expected to close by October 14, 2005.

The sale includes natural gas and oil properties in four fields in Oklahoma and Texas with estimated reserves of approximately 240 billion cubic feet of natural gas equivalent, as of August 1, 2005.

"With this transaction we will exit the oil and gas production business and will focus our attention on our other businesses, which include natural gas distribution, gas gathering and processing, pipelines and storage, energy services and natural gas liquids," said David Kyle, ONEOK chairman, president and chief executive officer.

ONEOK plans to use the proceeds from the sale to reduce debt.

Apache Restores More Oil, Gas Production

Apache Corp. on September 15 said it restored much of its oil and gas production that was shut in by Hurricane Katrina, but a smaller portion of its capacity may remain closed for up to a year.

The company said 81 percent of its natural gas production and 65 percent of its oil production on the Gulf Coast is back on line. That amounts to 459 million cubic feet of natural gas production per day and 45,600 barrels of oil daily.

Another 45 million cubic feet per day of natural gas and 4,000 barrels of oil should be restored by mid-October, Apache said. However, as much as 60 million cubic feet of daily natural gas production and 20,000 barrels of oil production may stay shut in for as long as a year.

So far, the company said its production in the Gulf Coast is at 87 percent of normal gas volume and 68 percent of normal oil volume.

Apache noted that it has $150 million in business interruption insurance to cover the lost production revenue. The company also has a $350 million property damage policy, after a $7.5 million deductible - but $250 million of this coverage is subject to adjustment depending on the hurricane-related claims of other companies.

The company's shares rose 85 cents to $71.85 in midday trading on the New York Stock Exchange.

Fourth LNG Terminal Plan for US East Coast

AES Corp, the US energy company, has proposed building a liquefied natural gas terminal on an uninhabited island near Boston harbor, putting it forward as an alternative to bringing LNG carriers near the city.

The AES project comes on top of two proposed offshore terminals, 10 miles offshore, and a third LNG project in Fall River that’s facing local opposition.

AES Corp. said the site, an unused state park known as Outer Brewster Island, would have more storage capacity than an existing Suez-Distrigas-owned LNG terminal in the town of Everett.

AES, based in Arlington, Virginia, would need a two-thirds majority vote by the Massachusetts state legislature to get access to Outer Brewster, even before pursuing other state and federal approvals.

“It's something worth at least considering and taking a hard look at,” said James Hunt, the energy and environmental aide to Boston Mayor Thomas Menino, in reference to the AES project.

Demand for natural gas has soared in the Boston area over the past five years after three big electric plants powered by natural gas went into service. Homeowners and businesses have also been steadily converting from oil to gas for heating, according to the Boston Globe newspaper.

In June, the Federal Energy Regulatory Commission approved the Weaver's Cove Energy Project in Fall River, though city officials are hoping it will reconsider after the area's congressman inserted a provision into a highways bill this summer that prohibited the demolition of a bridge blocking the proposed route for LNG carriers.

Kodiak Oil and Gas commences Drilling Operations in Wyoming

Kodiak Oil & Gas Corp. announced that a drilling rig is on location and drilling operations will commence September 21 on the Company's Chicken Springs Prospect (non-operator) in Sweetwater County, Wyoming. The Company owns a 50% before payout working interest in 6,552 acres and a 45% working interest in an additional 5,320 acres within the boundaries of the Chicken Springs Federal Unit.

On the Chicken Springs Prospect, two vertical wells will be drilled to an approximate depth of 6,000 feet. The development wells will be completed to test natural gas potential of the Almond Formation sands and coals. Both wells will be direct offsets to the PRFED 14100 SW29 well that has been producing from the Almond sands since June 2005. Completion work is scheduled to immediately follow drilling operations and the wells will be connected to the existing production facilities. Compression facilities will be installed while the drilling program is in progress, which should significantly increase production rates.

A third well will be drilled one mile west of the development wells in an attempt to exploit the potential of the Almond Formation coals in this part of the Chicken Springs leasehold. Kodiak and its partner, Warren Resources, Inc., intend to drill two laterals in the coal seam, each having lateral extents of 1,000-4,000 feet.

Kodiak President and CEO, Lynn Peterson, noted that, "During the drilling of the aforementioned PRFED 14100 SW29 well, a 16 foot coal seam was encountered at an approximate depth of 5,800 feet. Desorption analysis of sidewall core samples showed a very high gas content of approximately 500 SCF per ton. The same coal seam can be seen on logs from older wells in the area, as well as 2-D seismic acquired across the Prospect area. The potential gas reserves from the coals are very significant. These three wells represent an integral part of our 2005 exploration program."

The Company expects to have a second rig drilling on the adjacent Chicken Ranch Federal Unit within two weeks. The 8-9 Chicken Ranch Unit well (33.33% Working Interest; non-operator) will be drilled to an approximate depth of 8,600 feet to test the natural gas potential in the Almond and Ericson Formations. The Company owns an interest under 7,858 acres in the Chicken Ranch Unit.

Remington Oil and Gas Corporation Reports on Missing Rigs Following Hurricane Rita

Remington Oil and Gas Corporation announced September 26 that two offshore jackup drilling rigs under contract to the company are no longer at their pre-storm locations. All personnel aboard the two rigs were safely evacuated prior to the storm. The company currently has crews mobilized to assess conditions at both locations.

Sempra Checking for Damage at LNG Sites

A Sempra Energy spokesman said September 29 that they don't know how long it will take to determine what repairs, if any, will be required at sites for two planned liquified natural gas terminals in Cameron Parish, La., and Port Arthur, Texas.

The two sites were directly in the path of Hurricane Rita, but workers and equipment were moved from Cameron Parish before the storm arrived and construction has not started at the Texas site, the company said in a news release.

Spokesman Art Larson said Sempra has people in the area, but access to the properties is severely limited and they don't know yet when inspectors will be able to see the damage.

Only preliminary grading and site work had been started in Louisiana. Before the storm, the plant was scheduled to begin operating in late 2008, processing 1.5 billion cubic feet of gas per day. That's about half the amount of natural gas Southern Californians consume on average on a typical day, Larson said.

The Port Arthur facility is still in the permit stage, so work had not been scheduled to start on the 1.5 billion-cubic-foot plant until 2006, he said. That plant is being designed for an expansion that would accommodate doubling of its production.

Growing Ohio Gas Well Controversy Continues

With the price of oil and natural gas skyrocketing, will more wells be drilled in the urban areas across northeast Ohio?

Will they be drilling across Lake Erie and inside Ohio’s state parks?

There's a brand new well being dug in Gates Mills. It's just one of a growing number of rigs across northeast Ohio all pulling oil and natural gas out of the shale thousands of feet below the surface, and all pulling in cash royalties for their owners.

"By allowing this activity to take place on his land, he's contributing to the natural gas supply in his own backyard, his own neighborhood and his own state," said Thomas Stewart of the Ohio Oil & Gas Association.

With skyrocketing prices for natural gas, some Ohio Republicans now want to open all state public lands and Lake Erie for natural gas drilling.

But, critics of the plan say that drilling in Lake Erie won't happen without a fight.

Gulf Oil, Gas Output Still on Hold

U.S. Gulf of Mexico oil and gas production outages due to Hurricanes Katrina and Rita showed little improvement by September 30, according to the Minerals Management Service.

Some 1.467 million barrels of oil a day, or 98% of the region's oil output, remained shut-in as of 12:30 p.m. Friday, a slight decrease from 99% on September 29, said an MMS release. Natural gas outages stood at 7.94 billion cubic feet a day, or 79% of the region's gas production, down from 80%.

Oil production lost since Katrina-related evacuations started on Aug. 26 amounted to 40.8 million barrels of oil, or 7.4% of annual oil production in the Gulf. Cumulative lost gas production reached 196.5 billion cubic feet, or 5.4% of the region's yearly gas output.

Oil and gas production in the Gulf of Mexico, which amounts to one-fourth of the national total, showed some recovery in the days following Hurricane Katrina. But the arrival of Hurricane Rita, which triggered another round of evacuations and put additional pressure on limited quantities of personnel and equipment, pushed back the recovery schedule. Resumption of normal operations is also hampered by damages to pipelines and onshore gas processing facilities.

With winter around the corner, the slow pace of recovery in natural gas output will make further demand destruction via high prices necessary, some analysts fear. "If we don't get production returned soon, the market is going to take demand out," said analyst David Pursell, with Houston-based Pickering Energy Partners.

The area where demand could be impacted the most is among industrial users, which account for one third of the U.S. natural gas demand, said Pursell. The country's natural gas consumption for August reached 58.3 billion cubic feet a day, according to the American Gas Association.

Up to 10% to 20% of industrial natural gas consumption could be priced out if the nation starts the winter with a gas storage deficit, said Pursell.

Natural gas futures in the New York Mercantile Exchange closed at $13.92 cents, down 27 cents.

Several companies reported progress in bringing back a portion of their production.

Marathon Oil Corp. (MRO) said on September 30 that 36,000 barrels of oil equivalent a day remained shut-in, out of its net Gulf production of 60,000 barrels of oil equivalent a day. The company reported in a press release that its Ewing Bank platform suffered minor damages, but resumed production on Thursday.

Marathon's onshore Centennial pipeline, which stretches from Beaumont, TX to Illinois, was shut-down as a result of Rita-related power outages. Several of the company's Gulf of Mexico offshore pipelines remained shut-down due to shut-in production facilities and damaged onshore facilities, the release said.

Restoration of normal operations depends on repairs to offshore platforms, as well as availability of onshore facilities and pipelines "which were more seriously affected by the storm," the Marathon release said.

ExxonMobil Corp.'s (XOM) production shut-in stands at 50,000 barrels of oil a day and 570 million cubic feet of gas a day, the company said.

Forest Oil Corp. (FST) has restored 45 million cubic feet equivalent a day of oil and natural gas production, out of a total pre-storm output of 225 million cubic feet equivalent a day, the company said Friday.

Most of the shut-in is due to damaged pipelines and onshore gas processing plants offshore and in Louisiana, the company said in a release.

Forest reported five platforms damaged, which previously produced 6 million cubic feet equivalent a day. One non-producing platform was lost, the release said.

BP Launches Shutdown to Improve Alaska Oil-Field Safety

Oil giant BP, rattled by a string of industrial accidents, said September 28 it will shut down and refurbish dozens of oil wells on Alaska's North Slope as part of a multimillion-dollar campaign to improve safety.

The shutdown will knock out a big chunk of North Slope production - about 20,000 barrels a day - at a time when oil prices are running at historic highs in excess of $60 a barrel. Slope production has averaged 811,000 barrels per day so far this month.

But oil field safety trumps high oil prices, and a review of some 2,000 wells in the huge Prudhoe Bay field, as well as the neighboring Endicott field, found that about 70 oil wells need improvements, BP Alaska spokesman Andrew Van Chau said.

The review involved experts not only from London-based BP but from other major Prudhoe owners including Conoco Phillips and Exxon Mobil. BP runs Prudhoe, the continent's largest oil field, on behalf of the partners.

The review found wells that "presented a higher risk than we were ready to accept," Van Chau said. Problems include potential for leaks of oil, oily water or dangerous natural gas, as well as engineering or equipment shortcomings. The review also looked at field operating procedures.

Each well will be overhauled at a cost of about $2 million each, he said, putting the total price tag at $140 million.

"Our focus is on safety," Van Chau said. "We're looking at being on the North Slope for the next few decades."

The process of shutting down the wells began the last week of September, he said.

Steve Marshall, president of Anchorage-based BP Exploration (Alaska) Inc., spoke directly with Alaska Gov. Frank Murkowski about the well shutdown. Murkowski on Sept. 6 had asked BP and other oil companies to increase Alaska oil production to help ease an energy crunch caused by Hurricane Katrina.

John Norman, chairman of the Alaska Oil and Gas Conservation Commission, which regulates oil well operation, said his agency encouraged refurbishing the 70 wells, though he said none is out of compliance or unsafe.

Although the production decline hurts - the state collects millions of dollars in taxes and royalties on North Slope oil production - Norman said BP has "very valid reasons why they're undertaking this action."

The basic problem, Norman said, is that Alaska's oil fields are showing some age.

"Many of the wells at Prudhoe Bay are now 30-plus years old. You can imagine that any piece of equipment at that age can develop problems," he said. The onshore LNG plant at Wickham Point in Darwin is 90% complete, and the 512 kilometer pipeline from the Bayu-Undan field is finished and filled with gas, ConocoPhillips Darwin area manager Blair Murphy told Dow Jones Newswires in an interview.

"We're utilizing a little bit of the gas for commissioning the plant, but there's no revenue from that, it's for commissioning, running some of the power generation and the like," Murphy said.

CANADA

Canaport LNG begins Construction on LNG Regassification Terminal

The initial phase of construction for the Canaport LNG project begins in the middle of September at Irving Canaport. Clearing of the site was completed in May 2005. The initial construction phase involves site excavation and leveling, and is the precursor to full-scale construction.

Front end engineering design for the project is now complete, and

Canaport LNG issued a request for proposals for engineering, procurement and

construction (EPC) earlier this summer. Onshore construction is scheduled to

begin in Spring 2006.

Irving Oil Limited and Repsol YPF, S.A. announced in June that they had

formed a new partnership, Canaport LNG, which will construct, own and operate

the LNG regassification terminal in Saint John. The Canaport LNG terminal will

be operational in 2008, initially delivering 1 billion cubic feet per day of

regassified LNG into the market.

Delta Oil & Gas Acquires Additional Natural Gas Interest in Alberta

Delta Oil and Gas, Inc. (OTC BB: DOIG) announced it has entered into an agreement to participate in the drilling of a potential natural gas well in a highly prospective property discovered in the Deep Basin along the edge of the Alberta foothills belt approximately 80 miles Northwest of Calgary Alberta. ("Strachan Prospect").

The Strachan gas pool was discovered 35 years ago however in November 2004 Shell Oil announced a new Leduc Pool discovery at Ricinus with potential One Trillion cubic feet gas reserves. The Strachan prospect is 12 miles northeast of the Shell Oil discovery in the same part of the Deep Basin. The Strachan prospect is based on newly developed highly technical Three Dimensional Seismic programs that shed new light on identifying deeply buried full height and partial height pinnacle reefs.

The original Strachan Leduc discovery well was drilled in October 1967 by a junior oil company called Stampede Oil. Six gas wells delineate the aerial extent of this major gas pool with initial production rates to fill the maximum capacity of the Strachan Gas Plant at 250MMCF per day. After 20 years, key wells had cumulative production of between 150 to 225 Billion cubic feet natural gas each. To date, 962 Billion cubic feet of natural gas reserves have been recovered and currently only minimal residual gas production is pipelined to the under-utilized Strachan Gas Plant.

In participating in the Strachan prospect, Delta receives the benefit of the operator's expenditures to date in this area including land costs, 3 dimensional seismic costs, pipeline costs to the Strachan Gas Plant and the intangible value of their exploration team.

Delta has agreed to pay 4% of the costs of drilling and completion of the well and if natural gas is found in paying quantities.

Teck says it May Consider More Oil Sands Projects

Teck Cominco Ltd. is looking at the possibility of moving into more oil sands projects, chief executive officer Don Lindsay says.

Lindsay said the Vancouver-based mining company was courted by five oil sands players before it announced a $475-million deal earlier in September for a 15-per-cent stake in the Fort Hills energy project owned by Petro-Canada and UTS Energy Corp. "We're still evaluating other opportunities, and whether we do something sooner or later, it is really not clear," he told an investor conference September 26.

Teck had faced criticism over the deal from analysts who said the price was too high for the meager stake in the project.

Calgary-based Petro-Canada has agreed to pay $900-million of the first $1-billion spent on the project, which is expected to have a final cost of between $4-billion and $5-billion, for a 60-per-cent stake.

Mr. Lindsay defended the decision. "We're taking a fair bit of time at the beginning to set up the organization and make sure it has the right tone to it because we do want to bring a mining approach to these large projects and hopefully run it well," he said.

Total SA Says Deer Creek Oil Sands Project May Cost $9 Billion

Total SA, Europe's largest oil refiner, said the cost of its Deer Creek project may reach as much as $9 billion, including its initial $1.78 billion investment.

Total said it bought 78 percent of Deer Creek Energy Ltd., a Canadian oil-sands producer, and is now considering plans to invest about $4 billion in upgrading equipment.

``This investment is just the initial investment,'' Thierry Desmarest, Total's chief executive, said at a conference in London. ``It's just like the tip of the iceberg compared to what will have to be invested later on.''

Christophe de Margerie, Total's head of exploration and production, said in an interview at the conference that the total cost of the project would be about $9 billion. The project should produce about 200,000 barrels of oil a day, Total said.

Desmarest said that while Total still uses a $25 oil price target for projects, he doesn't expect prices to fall that far.

``Forty dollars to $45 a barrel can be considered a floor for coming years,'' Desmarest said in his speech. ``We still need to keep a relatively conservative price-scenario assumption.”

BRAZIL

Brazil's Oil Giant Gets License for Controversial Gas Pipeline in Amazon

Brazil's Environmental Protection Agency Ibama said September 8 it has licensed a unit of the state-run oil company Petrobras to start building a controversial gas pipeline cutting through pristine Amazon forest.

Petrobras and environmentalists have quarreled since 2001 over the planned 550-kilometer (345-mile) pipeline from the oil- and gas-producing region of Urucu in Amazonas state to the city of Porto Velho in Rondonia state.

Petrobras plans to use the pipeline to supply gas-fired power plants in Porto Velho.

The company currently re-injects most of the 9.3 million cubic meters (12.16 million cubic yards) of natural gas it produces in Urucu.

The license, given to a consortium controlled by Petrobras, runs until September 2009, Ibama said in a statement.

One of the prerequisites for the license was a construction project that did not interfere with national forests.

Also, the company will have to present a program to avoid diseases from spreading from construction workers to local Indian communities, and a program of environmental education for workers.

Environmental non-governmental organizations have been criticizing the pipeline project for years, arguing it would open a corridor into untouched rain forest that is likely to attract thousands of illegal settlers and lumber loggers and spoil the life of Indian tribes untouched by contact from the outside world.

Brushing aside the criticism, Petrobras President Sergio Gabrielli on Aug. 23 said Urucu "is an example of the balance between oil exploration and the environment.''

The firm also produces some 60,000 barrels of high-quality light oil there.

Roberto Smeraldo, head of the Brazilian affiliate of Friends of the Earth, however, said the transport of oil and gas through the Amazon has a serious impact on the environment.

"Oil and gas transport is dangerous in any situation. In a fragile ecosystem, this danger becomes even more intense,'' he said in August.

It was not immediately clear whether environmental groups would try to overturn the Ibama decision in the courts.

MEXICO

Report Spotlights Mexico-U.S. Energy Project

The scramble for energy in both the United States and Mexico will likely intensify the push for increased energy production and transportation in and around the border region. A new report by the Santa Fe, NM-based E-Tech International consulting firm reviews one long-planned project in Sonora State that could receive a shot-in-the-arm from the energy crunch. Authored by E-Tech International Director Richard Kamp, the report examines the general economic and environmental issues surrounding a proposed liquefied natural gas (LNG) regasification facility for Puerto Libertad, Sonora, on the Gulf of California.

Planned by Houston-based DKRW Energy, the plant will supply LNG to both Sonora and Arizona if it is constructed. A pipeline that could possibly cut across the international border in the Nogales region will be used to deliver the US-destined product. A second pipeline would snake south toward the Hermosillo, Sonora, market.

Expected to be supplied daily by at least two tankers carrying LNG, about 1.0 billion Cubic Feet per Day of product will be handled at the projected terminal. According to E-Tech International, DKRW Energy owns land already zoned for LNG in Puerto Libertad but still lacks authorization from the Mexican Federal Electricity Commission (CFE), Ministry of the Environment (Semarnat), Ministry of Labor, Ministry of the Interior, and the local fire department. Quoted in the report, DKRW Energy partner David Ramm expressed the intentions of his company to forge ahead with the necessary environmental permits.

Although it's uncertain whether Mexican residential consumers will benefit, big consumers of DKRW's LNG could include Guaymas sardine factories and a Ford plant in Hermosillo. Financing and marketing still need to be worked out for the terminal to be a reality but construction could begin next year and be completed by 2009.

While not giving an exhaustive analysis of the all the potential environmental impacts stemming from the proposed LNG facility, E-Tech International's report provides a sketch of some of the issues at stake. The LNG terminal is planned for a community, Puerto Libertad, which already has seen its share of environmental degradation from a large thermoelectric plant operated by the CFE. In the construction of the Puerto Libertad thermoelectric, the Mexican government drained and scraped the surrounding land, destroying a mangrove estuary.

To generate electricity, the plant uses combustoleo, a cheap, tar-distillate from the Mexican national oil company's refining process. The Montreal-based North American Commission for Environmental Cooperation estimates the Puerto Libertad plant emits 67,300 tones of sulfur dioxide annually, but air-pollution expert Kamp pegs the figure at probably more than 100,000 tons per year. If DKRW launches its LNG project, the existing thermoelectric plant could be converted to a user of much cleaner LNG. In contrast to the burning of combustoleo, E-Tech International's Kamp asserts that the ambient air regasification process planned by DKRW is environmentally benign. Broader concerns arise, however, over the global warming effect of methane released by LNG, according to Kamp.

Since the LNG will be shipped into Puerto Libertad, a key environmental consideration is the possible impact of ship traffic on the marine life of the Gulf of California. Kamp says a broad range of ecological concerns will have to be addressed in an environmental impact statement submitted to Semarnat.

Other developments in the works for the Puerto Libertad area will have an environmental and social impact in addition to the planned LNG terminal. Arizona Clean Fuels is contemplating an oil port.

The E-Tech International report cites another potential problem associated with the construction of a LNG terminal: the threat of catastrophe from either an accident or terrorism. Fears center on the flammability of an escaped cloud of gas, a disaster Kamp contends is best avoided by an offshore LNG terminal. The report's author says DKRW is not considering putting its plant offshore at the moment. Kamp adds he has "no answer" for whether there would be any environmental advantage to an offshore terminal — as opposed to hazardous emergency response — but the dilemma pf public safety versus ecological preservation is clearly "an important issue" to address in an environmental impact statement.

VENEZUELA

Chevron’s Deltana Gas Find in Venezuela enough for LNG Train

US oil company Chevron (NYSE: CVX) has found about six trillion cubic feet (Tf3) of natural gas in block 3 of eastern Venezuela's Deltana platform, enough to warrant the country's first liquefied natural gas (LNG) train, Ali Moshiri, the president of Chevron Latin America Upstream, told BNamericas.

Venezuela's energy and oil minister and state oil firm PDVSA president Rafael Ramírez said that the size of Chevron's Deltana find is closer to 7Tf3, but that even at 6Tf3 it is much more than original reserve estimates.

Chevron announced in June a "significant" natural gas find on block 3, one of five offshore blocks in Plataforma Deltana, but this is the first time the company has announced the size of the find.

The discovery was made at the offshore Macuira 1X exploration well in block 3. The well tested at a rate of 51 million cubic feet a day of natural gas.

The well is located relatively close to and on trend with the Loran gas field in block 2, where Chevron drilled four successful exploration wells in 2004.

Chevron operates block 3 with a 100% stake. PDVSA has an option to back into the block up to 35% upon declaration of commerciality. Chevron was awarded the license for block 3 in August 2004.

Chevron also operates block 2 with a 60% stake and fellow US company ConocoPhillips has the remaining 40%.

Chevron Awarded Exploration License in Gulf of Venezuela

Chevron was awarded on September 8 an exploration license for the Cardón III block off the coast of Falcón state in the western Gulf of Venezuela as part of the first stage of the government's Rafael Urdaneta tender.

Moshiri said he is eager to start exploration on Cardón III as soon as possible. Under the license conditions, Chevron is required to invest US$10mn in the first stage.

"Venezuela is very important for the world in terms of energy security. The Gulf of Venezuela has enough gas reserves [for commercial production], that's why it was so easy for us to decide about participating," Moshiri said.

Chevron already has offices in Maracaibo, the capital of oil-rich Zulia state bordering with Falcón state, but it could open another office with 20-30 people to deal with the Gulf of Venezuela exploration, Moshiri said.

2. ASIA

AUSTRALIA

S. Australia’s Beach Petroleum looking for another Oil and Gas Beachhead

South Australia will have another $1 billion-plus oil and gas company within three to five years if Reg Nelson has his way.

The managing director of Beach Petroleum has steered the company from a near-crippling fraud case at the hands of former directors in the early 1990s to its first offshore oil production, expected within months.

Beach has grown from the crowded ranks of oil and and gas minnows to a $371.5 million firm that plans to treble production to three million barrels of oil equivalent within two years.

Nelson is hoping Beach's Basker/Manta/Gummy (BMG) project in Bass Strait will do for the company what the Bodalla oil field in Queensland did for it over the past few years - give it the cash flow to take the next step in it evolution.

The 43-year-old company's recent strong growth started with a 22 per cent stake in the Bodalla block in southwest Queensland.

"We needed to build up that foundation in the Cooper/Eromanga (basin), focused on what we call the cornerstone cash generators," Nelson said.

"We were able to move to 100 per cent (of Bodalla). We were then able to re-invest some of the cashflow and build up reserves in those fields to the point where, what we thought we'd bought, we'd produced and sold already, and we still had as much there and probably more.

"We re-invested part of our cash flow from that into building reserves and production and we invested the rest into either more exploration in the South Australian section of the Cooper/Eromanga, or a little play here and there in offshore Western Australia.

"Now our South Australian production is almost starting to rival Queensland production."

With the oil price at record highs, the company is making more than $60-$65 net per barrel of oil it draws from the ground.

But the offshore Gippsland Basin is the target for the next, larger, cornerstone cash generator. Beach got into the BMG project about a year ago.

Anzon Energy had acquired it from Woodside Petroleum but needed help to get it started. Beach became a cornerstone investor in Anzon Australia, which floated in December, and also farmed into BMG.

This month shareholders approved a $75 million capital increase which allowed Beach to exercise a pre-emptive right in BMG, taking its share of the project to 37.5 per cent.

It has the option to increase that to 50 per cent this calendar year.

Nelson said the company had a policy of re-investing in current and lower-risk projects, while allocating about 10 per cent of re-investing cash flow in the higher-risk and higher-reward areas.

Now Beach is starting to look overseas for future projects. The company recently sponsored the first Australia India Business Council luncheon.

It is a sign it is broadening its outlook, beyond the Cooper/Eromanga basin and even offshore Australian projects.

Radical Method may Bury Massive Gorgon Gas Plant Project

The science of burying carbon dioxide gas 2km beneath the ground has emerged as a significant hurdle in the $11billion Gorgon gas project's bid for environmental approval.

The partners in the massive Gorgon project plan to cut greenhouse gas emissions by injecting carbon dioxide, captured in the process of taking natural gas out of the ground, back into wells drilled deep below Barrow Island off the West Australian Coast.

The controversial plan is the first attempt in Australia to use so-called geo-sequestration to offset greenhouse gas emissions - and environmentalists fear it will not work.

A 2500-page environmental impact statement, one of the biggest produced in Australia, was released September 12 to address concerns over the location of the planned Gorgon processing plant on Barrow Island. Barrow Island has been designated a class-A nature reserve for the past 95 years, with several species of animal unique to the island.

The project already has in-principle state government approval through an act of parliament in 2003 that allows it to use a maximum of 300ha of the island. But it needs environmental clearances from state and federal authorities.

The West Australian Environmental Authority opposed the choice of Barrow Island for the Gorgon facility, even though it has been the site of oil production for more than 40 years.

The Gorgon project - proposed by the giant Chevron group, partnered by Shell and ExxonMobil - has also attracted strong community opposition in Western Australia.

It aims to produce 10million tonnes of liquefied natural gas a year for export from 2010. And the partners warned they needed early government approvals to avoid missing the burgeoning market for LNG.

The EIS addresses three main issues: quarantining Barrow Island from the introduction of plants and animals from outside; the impact of dredging a 70km pipeline from the Gorgon gasfields; and the challenge of disposing of carbon dioxide, which makes up 14per cent of the Gorgon gas.

Carbon dioxide injection into geological structures below the surface - stopping it from reaching the atmosphere - has attracted strong criticism from environmentalists, who claim the technology is untested as a long-term solution to greenhouse gas emissions. In particular, there are concerns the carbon dioxide could leak out.

The technology has never been developed commercially in Australia, although the coal industry and the CSIRO are working on "clean coal" technology that would inject carbon dioxide captured in the mining and processing of coal back into the ground.

It is this kind of technology that would be encouraged under the Asia Pacific Partnership on Clean Development and Climate pact between Australia, the US, China, India and South Korea.

The EIS admits sequestration is "relatively new". "However, the technologies to be applied by the Gorgon joint venturers are well established in the oil and gas industry and are being used to inject carbon dioxide in other parts of the world," it adds.

The oil industry often injects carbon dioxide into reservoirs to help force oil to the surface.

The document says independent analysis shows the Gorgon development would be among the most greenhouse-efficient LNG projects in the world.

"The probability of CO2 migrating to the surface has been determined to be remote, with potential environmental consequences limited to localized impacts on flora and possible detrimental impacts on subterranean fauna," the EIS states.

But the Conservation Council of Western Australia claimed Gorgon had failed to detail how the carbon sequestration process would work.

McDermott Unit wins Australia LNG Contract

McDermott International Inc., the US engineering firm, said its J. Ray subsidiary was awarded a $77 million contract by Woodside Energy Ltd., operator of Australia’s North West Shelf liquefied natural gas venture.

Under the contract, J. Ray will undertake construction, engineering, procurement, fabrication, assembly and erection of 75 pre-assembled module and pipe rack units.

Completed modules and pipe racks will be shipped from J. Ray's Batam Island plant in Indonesia to Western Australia, and transported to the Burrup Peninsula, where Woodside and its partners are constructing the North West Shelf’s Train 5.

“The North West Shelf Venture contract is a welcome addition to our fabrication backlog at Batam, and work has already begun in preparation for this project,” said Bob Deason, President and Chief Operating Officer of J. Ray in a statement.

The six equal participants in the North West Shelf Venture are: BHP Billiton, BP, Chevron Corp., Japan Australia LNG, Shell and Woodside Energy. The China National Offshore Oil Corp. is also a member of the venture but does not have an interest in its infrastructure.

LNG Market to be developed in Australia

Growing demand for liquefied natural gas (LNG) in the global market is driving oil and gas firms' renewed interest in Australia, a government official says.

Oil firms had shied away from exploration as they mostly found gas, which could only be exported by costly pipelines until the advent of LNG, says John Griffiths, director general of offshore resources at Australia's ministry of Industry, Tourism and Resources.

But recently, majors like French energy giant Total SA , Royal Dutch/Shell and BP were showing renewed interest in exploration in offshore Australia, Griffiths says.

"The turnaround in the gas market has been critical in renewing interest in the country."

"The real issue for Australia is that by the virtue of its finds, it is a gas province but oil is a lot easier to develop. So if you are looking for oil but find gas, it is now easier to commercialize."

He says the government's priority was to develop LNG, gas that is super-cooled into liquid form so that it can be transported by tanker.

Analysts say record high oil prices are unlikely to stem Australia's ailing oil production after a string of disappointing wells and high costs of exploring the vast and remote offshore regions.

Griffiths is optimistic about LNG prices remaining strong.

ConocoPhillips Pumps First Bayu-Undan Gas

U.S. oil giant ConocoPhillips Inc. (COP) has pumped the first gas from its Timor Sea Bayu-Undan-to-Darwin pipeline and production from its US$3.3 billion liquefied natural gas project is on track for early next year.

The Bayu-Undan LNG project will export 3 million metric tons of LNG a year to Japan, where the country's biggest electric power and gas firms, Tokyo Electric Power Co. (9501.TO) and Tokyo Gas Co. (9531.TO), have contracted to buy all the planned gas production from the project over 17 years.

The project, which ConocoPhillips operates and owns 56.7%, is being built in two stages, with the first, involving liquid production at the Bayu-Undan field between Timor and Australia's Northern Territory, well underway.

Liquid petroleum gas in the form of propane and butane has been produced from the Bayu-Undan field since early 2004. It is processed offshore and exported.

Gas from condensate produced along with the LPG is then injected back into the field to be piped to Darwin.

Murphy said first production from the Darwin LNG plant will be in the first half of next year but is reluctant to be more specific. People familiar with the project say it is likely to be in production in the first quarter.

"We're finishing off the last 10%, which involves finishing putting it together and testing the various vessels and equipment, pressuring them up to make sure they're all working correctly," Murphy said.

The Darwin LNG plant, which has a single processing train, has the potential to grow threefold if ConocoPhillips and its partners can find more gas and customers to buy LNG.

"We have places for two trains, and we are waiting for gas and for markets to develop," Murphy said. "Our current process train is for 3.24 million tons per annum and we have permits for 10 million tons per year up there."

The entire proven gas reserve at Bayu-Undan is contracted to the Japanese companies so the extra permitted capacity and place for a second processing unit means there is an opportunity for other gas fields in the Timor Sea to provide gas to the Bayu-Undan project.

This was highlighted September 29 when Australian oil and gas producer Santos Ltd. (STOSY) said it found a new gas field at its Caldita exploration well near Bayu-Undan.

Santos shares surged 6% to a record on the find, which it described as "encouraging" and "significant" but gave no indication of the quality of the gas.

ConocoPhillips took a 60% interest in Caldita last year with a view to tying in any gas discoveries to the Bayu-Undan project. Pre-drilling estimates of Caldita has the field containing 1.5 trillion cubic feet of gas, a Santos spokeswoman said.

"If Caldita contains 1.5 trillion cubic feet of clean gas, it could in theory provide the initial support for the building of a second 3.2 million tons-a-year LNG train at the Bayu-Undan LNG plant," UBS analyst Gordon Ramsay said.

But while Santos and ConocoPhillips have reported a new gas find with an encouraging flow rate of 33 million cubic feet a day, they have given little indication of the quality of the gas. Santos says further analysis is required before this will be known.

Caldita is next to the Santos-operated Evans Shoal field, which hasn't been developed, despite containing an estimated 6.6 trillion cubic feet of gas.

"Our best guess is that Caldita contains carbon dioxide, but how much is open to debate," Ramsay said. "If Caldita contains around 30% carbon dioxide it will in all probability sit undeveloped for some time, like Evans Shoal."

ConocoPhillips’ partners in the Bayu-Undan LNG project are Italian firm Eni S.P.A. (ENI.MI), with 12.1%, Santos with 10.6% and Tokyo Electric Power and Tokyo Gas owning a combined 10.1%. Inpex Corp. (1604.TO) owns 10.5%.

CHINA

China Invests $15 Million in Oil, Gas

The Chinese National Petroleum Corporation has invested more than 15 million dollars as training fund in the oil and gas sector in Africa “in the last few years”.

The Deputy Director-General, International Department, CNPC, Ms Pei Ying, said this in Beijing when 22 journalists from 16 English-speaking African countries visited the corporation.

Pei said that 35 teachers were sent to China to receive a petroleum engineering education. She said the corporation had also invested 20 million dollars on local utilities in Africa and stressed the need for Sino-African relationship to be further strengthened.

She, however, noted that the activities of the corporation were mainly in French-speaking countries and Sudan.

In 1997, CNPC participated in petroleum exploration and development activities in Sudan, she added.

The CNPC not only developed and constructed a 10-million ions capacity oil field but also completed an oil pipeline with a length of 1,506km, the longest in Africa.

“The Khartoum Refinery with an annual crude processing capacity of 2.5 million tonnes was completed and it adopted the technology and standard from China,” She said.

In Nigeria, Pei said the corporation had shown interest in the management of the Kaduna refinery and that discussion on its eventual take over was scheduled.

INDIA

ONGC Oil Rig Fire Destroys Equipment worth Millions

Massive flames leapt up to deafening blasts as a rig of the Oil & Natural Gas Corporation (ONGC) in Andhra Pradesh caught fire September 8, destroying equipment worth millions and leading to the evacuation of hundreds of families.

The devastating fire began in the afternoon at the Krishna-Godavari basin and continued to rage in the evening even as fire-fighting teams from ONGC, navy and Visakhapatnam Steel Plant tried to douse the flames.

Three villages surrounding the rig at Tandavapalli village, seven kilometres from Amalapuram town in East Godvari district, were emptied as a precautionary measure.

The flames rising to a height of 160 meters spread panic in the region. Locals said the fire appeared to be worse than the one at Pasarlapudi oilrig in the same district in 1995.

The fire that broke out around 11.30 a.m. has caused huge losses to ONGC. Drilling equipment worth Rs.500 million and six vehicles has been gutted in the fire.

Fire brigades from nearby districts could do little. They could not even go near the rig as flames leapt with deafening blasts. ONGC personnel equipped to handle such accidents were mobilized from Rajhamundry, 70 km away.

Fire-fighting equipment and personnel from Eastern Naval Command headquarters in Visakhapatnam were airlifted by helicopters.

Petronet LNG Closes Dahej after Jetty Hit

GAIL, the Indian gas transport company, and India’s Petronet LNG, said they temporarily closed the Dahej liquefied natural gas receiving terminal in the western state of Gujarat after tug boats pulling an LNG carrier that was casting off after unloading smashed into a jetty.

The companies said the accident happened on September 17 and LNG cargoes would be diverted to India’s only other terminal at Hazira, also situated in Gujarat and operated by Shell, while repairs are carried out.

In a statement to the Mumbai Stock Exchange, GAIL said the accident happened during winds of 40 knots when the LNG carrier Disha was being moved by tugs.

Petronet which operates the Dahej terminal and Gaz de France as a partner, as well as several other Indian state energy groups, has approached foreign companies to assess the damage and repair the terminal, GAIL said.

Ras Laffan Liquefied Natural Gas Co. of Qatar and Petronet signed an agreement in January 2004 for the supply of 5 million tonnes par annum of LNG to India under a 25-year contract, with supplies being received at Dahej where there are moves to expand capacity to handle 10 MTPA.

INDIA / PAKISTAN

India and Pakistan May Require more than Two Gas Pipelines

India and Pakistan may require more than two pipeline schemes for importing gas from countries like Iran, Turkmenistan, Qatar and Oman, as the demand in the two South Asian nations is slated to increase to 50 billion cubic meters in the long term, a senior ADB official said.

"The US$7 billion scheme to pipe natural gas from Iran to Pakistan and India is gaining momentum," Dan Millison, senior energy specialist in the Asian Development Bank, said adding that with long term gas demand from India and Pakistan estimated at 50 BCM a year, there is a need for more pipelines.

Citing the recently released reserves information from Turkmenistan, he said the proposed US$3.3 billion pipeline project to carry gas from Turkmenistan to India and Pakistan would be lower than expected.

India already imports gas and demand will soar in the next decade, the ADB official said, adding Pakistan, with its own reserves declining, is expected to begin importing gas after 2008.

"Projected demand in South Asia is so strong that there may be a need for a third pipeline from Qatar or Oman," he said while predicting that gas from Turkmenistan to the South Asian nations would be lower than expected.

Turkmenistan's Dauletabad gas field has gross reserves of 1.4 trillion cubic meters of gas, but production forecasts are lower than expected, causing analysts to doubt that it can meet the proposed target of piping 30 billion cubic meters (BCM) of gas a year to South Asia.

JAPAN

Japan's Biggest Shipping Firm to add more LNG Tankers

Nippon Yusen KK, Japan's biggest shipping company, has upwardly revised its plan to expand its fleet of liquefied natural gas (LNG) tankers, a major Japanese financial paper reported September 21.

Nippon Yusen's initial business plan called for it to either own or have invested in the construction of about 60 such tankers by fiscal 2010. It has now raised that figure to roughly 80-100 tankers, the Nikkei Shimbun said.

As the US and other countries are expected to dramatically increase their LNG import volumes, foreign tanker transport firms are scrambling to keep pace. By increasing its fleet, the firm aims to ship more of the fuel, according to the report.

Because building an LNG tanker is costly, running about JPY 20-30 billion (USD 180-270 million) each, more shipping companies and LNG development firms are jointly investing in their construction. At present, Nippon Yusen has stakes in 33 LNG tankers and the firm has upgraded its plan to raise this number to 80 in fiscal 2010. The Tokyo-based shipping firm may raise the number to about 100 tankers around 2010, depending on orders.

Worldwide LNG production by 2010 is projected to be 2.8 times the volume seen in 2000.

Japan’s JGC Wins Ras Laffan Deal

Japan-based JGC says it has won a contract from Shell to build a 70,000 bpd gas-to-liquid plant and 100,000 bpd natural gas liquid recovery unit in Ras Laffan, according to Reuters. The plant, to be built with US-based Halliburton subsidiary Kellogg, Brown & Root, is expected to start operations in 2009, and the size of the order is likely to exceed an earlier estimate of $6bn.

MALAYSIA

Malaysian Complex could up LNG Output 20 Percent

Malaysia could raise production capacity at its LNG complex, the world’s largest, by about 20 percent in five years and is likely to sound off potential customers, a senior industry source said on September 23.

The liquefied natural gas (LNG) complex in Bintulu in Malaysia’s eastern Sarawak state can compress natural gas drawn from under the ground or seabed and convert it into 23 million tonnes of super-cooled liquid gas a year for export. But production at the facility, run by state oil and gas company Petronas, is almost completely sold out for the next 20 years, while global demand for LNG continues to grow.

The source said by overhauling the eight liquefaction trains, which turn gas to liquid, at the three plants in the complex, Petronas could squeeze out another 2 million tonnes of LNG, bringing the annual capacity at Bintulu to 25 million tonnes. But for Malaysia to capture more LNG orders, such as the additional 4.5 million tonnes South Korea says it needs from 2010, Petronas may have to expand the complex, said the source, who is familiar with the company’s thinking.

“There’s space at Bintulu and looking at the phenomenal forecasts for energy demand and prices over the next few years, Petronas could add a few liquefaction trains or even build a new LNG plant there,” the source told Reuters. The new investment could be at least $1.5 billion, that is the typical cost for a train with a capacity of 3.6 million tonnes, he added.

The new train — and the additional 2 million tonnes from the overhaul of existing facilities — could take Bintulu’s capacity to almost 29 million tonnes in five years. “The timing is dependent on the market. Once a decision is made, it should take about two to three years for it to be operational,” the source said, adding that Petronas was checking out possible supply contracts. Officials at Petronas would not comment.

The source said new gas discoveries in deepwaters off eastern Sabah — a state next to Sarawak on Borneo island — could justify an expansion of Bintulu’s plants, whose shareholders include units of Royal/Dutch Shell and Nippon Oil Corp Shell and Murphy Oil Corp. have announced major oil and gas finds off Sabah over the last two years in production-sharing contracts with Petronas.

“It’s still early to say what those discoveries could yield in terms of gas,” said the source. “But they could be significant enough to change the equation on reserves.” In order to raise LNG production, Petronas would have to weigh demand for exports against domestic gas needs and reserves.

“It will depend much on how the LNG market develops and how confident Petronas is about its reserves,” said the source, involved with Malaysia’s energy industry for about a decade. A Petronas executive told Reuters in July the firm had committed almost all of the gas it produces from the three Bintulu plants to South Korean, Japanese and Taiwanese buyers for the next two decades. De-bottlenecking, or modification, was underway at one of the plants to boost capacity for clients needing spot LNG cargoes, the official said.

NEW ZEALAND

Swift says Oil, Gas Flow at Piakau Well

Houston-based explorer Swift Energy Co said September 7 that oil and gas were flowing at its Piakau North A-1 well in New Zealand.

The well had tested at rates of up to 7 million cubic feet of gas and 400 barrels of condensate and was undergoing long term production testing, it said.

Piakau is in the TAWN area of Taranaki, an area encompassing four fields - Tariki, Ahuroa, Waihapa and Ngaere - and the gas from the well was being mixed with other production from the field.

Swift said it was looking at any changes to processing facilities to process greater amounts of gas from the field.

A second well in the prospect is currently being drilled and a third is also planned.

In March, Swift formed a joint venture for exploration with state-owned power company Mighty River Power for three exploration wells in Swift's TAWN and Rimu/Kauri fields.

New Zealand production for Swift last year was 16.3 billion cubic feet equivalent, which was more than a quarter of the company's total production.

New Zealand produces around 240 petajoules (69.79 billion cubic metres) of natural gas a year, of which around 40 per cent is used for electricity generation. However, the search for new gas supplies has intensified given the rundown in the dominant Maui field is nearing the end of its commercial life.

PAKISTAN / ALGERIA

Pakistan/Algeria Agree to Exchange Oil, Gas, Mineral Experts Delegations

Pakistan and Algeria have agreed to exchange oil, gas and mineral experts' delegations for exploring areas of cooperation between the two countries.

This unanimity of views arrived at a meeting between the visiting Algerian Minister for Small and Medium Enterprises Mustapha Binbada and Federal Minister for Petroleum and Natural Resources Amanullah Khan Jadoon during the meeting in September.

Welcoming the Algerian delegation, the minister said that both the countries were striving to achieve economic prosperity and have a lot of scope for interaction in diversified fields including oil, gas and mineral sectors.

He said that Algeria is a country rich in oil and gas and has great expertise in gas pipelines Liquefied Natural Gas (LNG) and minerals, adding that Pakistan can benefit from its expertise.

He briefed the Algerian dignitary about the upcoming trans-national pipeline, LNG projects, and ongoing mineral activities in the country.

The minister invited them to participate in these development activities for promoting bilateral cooperation. He hoped that Pak-Algeria JMC meeting would open up new vistas of cooperation between the two countries for their mutual advantage.

The Algerian minister, on this occasion, said that exchange of energy expert delegations would help bring the two countries closer.

He invited the minister for Petroleum to visit Algeria to help boost bilateral ties

3. EUROPE / AFRICA / MIDDLE EAST

FRANCE

Gaz de France, Gazprom to Cooperate in LNG Production

Russian gas giant OAO Gazprom and Gaz de France are considering cooperation in the production and sale of liquefied natural gas (LNG), the companies said in a joint statement on September 19, after a meeting between Gazprom CEO Alexei Miller and Gaz de France Chairman and CEO Jean-Francois Cirelli.

"The chairmen of Gazprom and Gaz de France also discussed the bright prospects for the production and sale of liquefied natural gas, which is becoming increasingly important on the energy market, as well as setting out guidelines for the teams working in this area with a view to developing joint projects," the statement said.

"Gaz de France has a lot of LNG experience, in which Russian gas companies have been very interested recently. Recently Gazprom supplied its first consignment of LNG to the U.S. Consequently, a new route has opened for Gazprom's development and, I think, given our knowledge and developments, Gaz de France participation in Russian LNG projects could show results and be mutually beneficial," Cirelli said in an interview with the newspaper Trud on September 20.

Gaz de France currently has long-term contracts with Gazprom for 12 billion cubic meters of gas, making up almost 25% of its long-term supplies.

"At the moment our company is the fourth largest buyer of gas in the world, and the third largest in Europe and the first as regards purchases of LNG. Our positions are firm, but we need to develop new growth areas - for example, by implementing projects at the start of the gas chain, in electricity production, in the service sphere. We have already developed such projects and we would like to implement them with other companies, with which we have cooperated for many years, particularly Gazprom," Cirelli said.

GERMANY

E.ON to Buy Caledonia Oil & Gas for $834 million

E.ON AG, Europe's largest publicly traded utility, agreed to buy Caledonia Oil & Gas Ltd. for 470 million pounds ($834 million), increasing its access to natural gas reserves as worldwide competition for the fuel rises.

Caledonia's gas output will increase E.ON's production capacity fivefold to cover as much as 5 percent of the needs of E.ON Ruhrgas AG, E.ON's natural-gas unit, said Josef Nelles, spokesman of the Dusseldorf, Germany-based company.

``Caledonia brings us significantly closer to our goal of covering up to 15 to 20 percent of the gas needs of E.ON Ruhrgas from our own production,'' E.ON said. ``The acquisition fully meets our stringent investment criteria.''

Natural gas, burned to heat homes and generate electricity, is increasingly being used as a fuel, raising its value and leading companies to seek access to reserves in countries ranging from Iran to Norway. Wholesale gas prices in the U.K. climbed 44 percent in the second quarter from a year earlier.

Caledonia is the first natural-gas production company E.ON will run. The German company will purchase Caledonia from investors including buyout firm First Reserve Corp., using loans. The price includes 70 million pounds in debt.

E.ON shares, which have advanced 15 percent this year, rose 1.3 euros, or 1.7 percent, to 77.26 euros in Frankfurt.

The U.K. company currently produces natural gas in four fields off the eastern coast of the country. E.ON will invest another 300 million pounds, helping Caledonia to start producing natural gas in 11 more fields in the next two to three years.

The purchased company alone will be able to cover 4 percent of Ruhrgas's annual needs of 56 billion cubic meters. Its reserves of 14 billion cubic meters are enough to supply 9 million households and will be developed over the next 10 years.

E.ON, with more than half the market for the fuel in Germany, also has a 30 percent stake in a gas field off Norway and 5.2 percent of a another field of the coast of the U.K.

Chief Executive Wulf Bernotat is negotiating with OAO Gazprom, the world's largest natural-gas producer, to pump gas in Russia. As he tries to increase access to the fuel he is facing competition from rivals such as BASF AG, the world's largest chemicals company, which is also talking to Gazprom about producing gas in a Siberian field.

The field holds 700 billion cubic meters of gas and is capable of producing 25 billion cubic meters a year. E.ON already had a small gas exploration venture, which came as part of its oil producing activities, which Bernotat's predecessor sold in 2001, as E.ON abandoned businesses outside natural gas and electricity.

In Germany, the number of homes heated with natural gas increased almost 3 percentage points in four years to 47 percent in 2004, according to figures from Ruhrgas.

The use of natural gas to fire power stations is also rising. German utilities generated 9 percent of their electricity by burning natural gas in 2004, twice as much as 10 years ago.

ITALY / GREECE

New Italian-Greek Pipeline Eases Some Supply Security

The proposed pipeline link between Italy and Greece is set to receive formal ratification in the next few weeks. The construction of the pipeline will bring positive developments to the gas industries in both countries, though further highlights how Europe is becoming increasingly dependent on gas supplies from outside the EU.

Recent signals indicate that Italy and Greece will formally sign an agreement to construct a pipeline link between the two countries in early November. The pipeline project, known as the Progetto Grecia e l'Italia, will be constructed by a joint venture partnership comprising Depa, the Greek national gas company and Edison, Italy's second largest power generator and an increasingly prominent player in the gas market. The signing of the agreement will serve to formalize the Memorandum of Understanding signed between the two countries earlier this year.

The construction of the 8 billion cubic meters per year link will be a significant development in the evolution of the fledgling Greek gas market when it comes on line in 2010. The completion of the link will open up a potentially significant role for Greece as a gas transit state - when completed the pipeline will link into another pipeline traversing northern Greece. This project will in turn interconnect with the pipeline link between Karacabey in Turkey and Komotini in northern Greece which is currently under construction. Collectively these three projects will form part of the South Mediterranean gas ring, a project awarded funding by the EU as part of the trans-European energy project program.

By increasing throughput volumes and creating a larger incentive for uninterrupted supplies, the completion of the wider project will bring a much needed element of security of supply to the Greek gas market. Currently over 90% of gas consumed in Greece is imported from Russia under a long term contract with Gazprom. The remainder consists of minute (and declining) levels of indigenous production and, since the construction of a regasification terminal in 1999, LNG imports of around half a billion cubic meters per year from Algeria.

This high level of import dependency raises various supply diversity and security issues. Securing new and diversified gas supplies is key to the future development of the Greek gas sector. Given its low levels of gas penetration, currently less than 7% of the primary energy mix is made up of gas, Greece is certain to continue experiencing rapid demand growth in the short to medium term. While the power generation and industrial and commercial sectors will continue to be the key driver of this demand growth, increased gasification and expansion of the distribution network will also result in rapid demand growth in the residential sector.

From the perspective of Italy, the link with Greece opens up other supply sources. Edison will use the gas imported via Greece to feed not only its gas fired power generation facilities but also its growing number of end use customers. Further to this, there is the potential to re-export the gas delivered to Italy to western European markets - though this gas will face significant competition from both Norwegian and Russian gas seeking to gain additional market share by further filling the gap left by Europe's declining indigenous reserves.

Although the addition of another conduit for non-Russian gas into Western Europe will be seen as a positive step for the security of supply of the European market, it does again serve to highlight the inescapable fact that the European gas market is increasingly dependent on gas sources from beyond its own borders.

NORWAY

Norway Ship Owner Fredriksen goes for Floating Production

Ship owner John Fredriksen, considered Norway's richest person has decided to turn to floating oil production as his next project. He is already the world's leading shipper of crude oil, and is also on his way to establish a considerable fleet of rigs for oil exploration.

According to Aftenposten, Fredriksen is now putting NOK billions into floating production facilities, through his own shipping company Frontline.

The market for these ships is now at a peak, according to Frontline Management CEO Oscar Spieler.

New Gas Find for Hydro

Norwegian petroleum giant Hydro's new find of gas at Stetind off the coast of Helgeland in Nordland County may be massive.

Nordic investment house ABG Sundal Collier referred to a Hydro source that claimed seismic data from Stetind indicated the field could be one of the last great finds on the Norwegian shelf, newspaper Finansavisen reports.

Finansavisen said that an estimate of 500 million barrels of oil equivalent would not be unreasonable for a find of this type.

"The well has given us positive information and is positive for Hydro's position and the future development of the area. Technical assessments remain, and there is a need for further exploration wells, before it can be determined whether the find can be exploited commercially," Lars Christian Alsvik, head of the Development Norway sector in Hydro Oil & Energy, said in a statement.

The Stetind find is the sixth oil and gas find made by Hydro on the Norwegian Continental Shelf so far this year.

ROMANIA

Falcon Oil & Gas Announces Results of Romanian Exploration Well and Operations Update in Hungary

Falcon Oil & Gas Ltd. (TSXV: FO) announced September 12 the preliminary results of its first Romanian coalbed methane well and provided an update of its deep gas project in Hungary.

Falcon's Lupeni South-1 well in the Jiu Valley Coal Bed Methane Concession in Romania has reached the primary target of Coal Seam #3. There were numerous gas shows in Seam #3 and also in the secondary targets in Seam #13 and Seam #14. The gross thickness of Seam #3 is approximately 21 meters, over an interval from 309 to 330 meters.

The core analyses and preliminary desorption measurements in the field indicate the potential presence of coalbed methane in multiple horizons but give no indication at this time of the potential gas production rates or recoverable reserves to be expected.

Based on the gas shows and core information, Falcon and the other working interest owner in the prospect, Pannonian International, Ltd., a wholly-owned subsidiary of Galaxy Energy Corporation, have determined to enlarge the cored section to run casing to total depth and to commence completion and testing operations.

Falcon has earned a 75% working interest in the 21,538-acre Jiu Valley coalbed methane concession, while Pannonian retains a 25% working interest.

"We are pleased with the initial results from our first well in Romania," stated Marc A. Bruner, President, CEO and Chairman of Falcon. "The drilling of this well confirms our geological model, which was derived from our research into the Romanian coal mining records. The three main coal seams were encountered at the depths and thicknesses that were predicted by our geologists. We also have some initial field measurements of the gas content of the Romanian coals that are encouraging.

"The next step for us is to enlarge the hole to run production casing. We have engaged Schlumberger's top team of coalbed methane experts in Pittsburgh to design and supervise the hydraulic fracture stimulations. While the subsequent completion and testing operations will ultimately determine the potential of this particular well, we believe we're off to a great start in Romania."

Falcon has conducted and interpreted a 3D seismic survey over a 16 square kilometer portion of the Tisza License area. In addition, it has purchased and reprocessed an additional set of 3D seismic data covering the southern portion of the Tisza License. Based on the new seismic data, Falcon has finalized the first three drilling locations in Hungary. Falcon will drill a deep well on the Mako License at the Mako 5 location and two intermediate depth wells-the Szekkutas well on the Mako License, and the Pusztaszer well on the Tisza License.

Marc A. Bruner commented, "The 3D seismic data has greatly increased our understanding of the geology in this massive basin. By collecting and interpreting the 3D data over the summer, we have come up with multiple drilling locations, three of which will be drilled in our fall program. We have a large inventory of premium casing and two drilling rigs under contract, so we're ready to start drilling. Our operations group plans to start building the first of the surface locations for these wells within a week, with the goal of having both rigs moved in and working in October.

UNITED KINGDOM

Germany’s RWE Unit Offered Oil, Natural Gas Blocks

The German power company RWE AG said September 9 that its British subsidiary, RWE Dea UK, was offered five oil and natural gas exploration blocks in the North Sea.

The offer came after the United Kingdom Offshore Licensing Round made blocks available for exploration and, if found, drilling.

Granby Oil and Gas Successful in North Sea License Round

Granby Oil and Gas plc has announced that it has been offered 12 additional blocks and part blocks to be held under six licenses in the North Sea as part of the 23rd UKCS Licensing Round announced by the DTI. Granby received one of the highest number (11) of operated blocks for an independent company.

This award takes Granby’s acreage position in the North Sea to 22 blocks and part blocks in total, and has significantly strengthened the company’s presence in its existing core area in the central North Sea, and brings the company into the Southern Gas and Firth of Forth basins for the first time. A number of the blocks offered are adjoining Granby’s existing licenses, where cross boundary prospects had previously been mapped.

Granby has been offered one traditional license with a seismic work program, and five promote licenses with work programs including reprocessing and re-evaluations of pre-existing datasets. The geophysical company TGS-NOPEC is a 33.33% partner with Granby in a number of the promote license awards. Faroe Petroleum plc (as operator) is also a partner with Granby in one of the awards.

Applications for blocks 13/25, 14/9, 43/7 and 44/27b were made under an existing Acquisition and Alliance Deed, under which Elixir Petroleum Ltd has the option to be assigned one half of Granby’s interest in these blocks.

Commenting on these awards, Managing Director David Grassick said;

“These awards enable Granby to continue its successful strategy of building a significant portfolio of assets through the discovery and exploitation of oil and gas reserves in the North Sea. The new plays and prospects in this acreage have increased the value and diversity of our portfolio significantly.”

Total Awarded Three Offshore Production Licenses in UK 23rd Round

Total announced that it has been awarded the three offshore production licenses it applied for under the 23rd Oil and Gas Licensing Round of the United Kingdom’s Department of Trade and Industry.

Total will be the operator with a 100% interest of the licenses for blocks 3/25-b, 4/21 covering an area of 183 square kilometers to the south of the Alwyn field 440 kilometers north-east of Aberdeen and for blocks 8/14, 8/15 with an area of 420 square kilometers, some 300 kilometers north-east of Aberdeen.

Total also has been awarded a stake of 43.25% in block 9/9c to be operated by BP and covering an area of 43 square kilometers adjacent to the Bruce field, in which Total already holds the same interest.

These awards illustrate Total’s commitment to continue exploration of the UK continental shelf and to actively participate in the further development of the North Sea oil and gas potential.

Don't Overlook Significance of UK Offshore Oil and Gas Industry says UK Offshore Operators Assoc.

With crude oil and natural gas prices continuing to dominate the headlines amid calls for additional investment in global oil production and refining capacity, UK oil and gas producers are playing their part and investing hard in the mature North Sea to maximize recovery of the country's reserves, estimated to be up to 28 billion barrels. But the industry's efforts to stem the rate of UK production decline would be derailed by further tax hits, poor regulation and escalating costs.

This message was delivered by Malcolm Webb, chief executive of the industry trade body, the UK Offshore Operators Association, at a fringe meeting at the Liberal Democrat Party Conference on September 19.

He said: "Last week the Chancellor called for additional investment in oil production.” UK oil and gas producers are already doing just that. Exploration of the UK continental shelf for new fields is up this year as is the number of new production wells drilled to date. The industry invested over £8 billion last year. This year, we expect that figure to rise by as much as 25 percent to £10 billion.

"The industry's efforts to stem the rate of UK production decline are paying off and current investment plans will see the rate halved to 7 percent per annum. This means we expect UK fields to be producing for decades to come, and in 2020 should still be meeting 65 percent of all our oil needs and a quarter of our gas needs.

"If we don't produce it, we will have to import it. Producing our own oil and gas saves this country £30 billion on its balance of trade and will generate more than £10 billion in tax for the Treasury, more than double the amount paid last year. Not only does it provide a secure source of primary energy, but is also supports over a quarter of a million jobs across the UK.

"This industry has invested a total of over £330 billion since the first exploration licenses were issued more than 40 years ago. It has recovered 34 billion barrels of oil and gas from Britain's often hostile offshore environment, risking not one penny of taxpayers' money but, on the contrary, earning this country more than £200 billion in tax revenues in total. Furthermore, UK gas fields have supported the expansion of direct gas usage and gas fired power stations in the UK which have been the major contributor to the UK meeting its Kyoto targets.

"The next chapter in the industry's history is now being developed on the already considerable presence of UK expertise, goods and services in the world energy market, which can continue to grow and create wealth for many decades yet to come.

"We should therefore be doing everything possible to build on and sustain one of the UK's most remarkable post-war industrial success stories. The country's reliance on oil and gas is growing, and government forecasts suggest that by 2020, 85 percent of our primary energy needs will be met by these resources.

"Yet I fear that we are still in danger of overlooking the significance of this great UK industry, which must not be put at risk from poor regulation, escalating costs and further tax hits. These would undermine investor confidence and erode international competitiveness, the very factors that will determine how long we can continue to produce economically from the North Sea.

"Oil companies sustaining high levels of investment in production are only one side of the coin. The other side is for government policy makers to work with industry to create the right business climate that will support UK oil and gas production in the long term."

WEST AFRICA / CENTRAL ASIA

India Eyes Oil and Gas in Africa, Central Asia

With most of the oil and gas discoveries being made in Africa and Central Asia in the last five years, energy-hungry India is keenly networking at the ongoing World Petroleum Congress to seek greater collaboration with these countries in the hydrocarbon sector.

"Africa presents a huge opportunity for us as it is estimated to hold over nine per cent of the world's reserves, most of which are still undiscovered. We want to participate more in Nigeria, Angola and some of the other West African countries," a senior Petroleum Ministry official of the Indian delegation said.

On offer are new exploration projects in a number of countries like South Africa, Namibia, Sudan and Madagascar that are keen to increase their output while Mozambique and Tanzania have emerged as first time gas producers.

According to a new publication 'African Oil and Gas: The New Horizon' released by PricewaterhouseCoopers (PwC) at the conference, "Africa yields the highest return on investment - four times more than the G7 countries and twice as much as Asia."

Business advisers to the Petroleum Congress, the PwC's Africa Energy Group stated: "All these positive developments have resulted in the US and China being at the forefront of global energy consumers to seek more of their supplies in Africa."

The global consultants expect Africa to play an important role in easing the current supply and demand scenario, with "heightened interest in exploration and production projects on the continent."

India's recent experience in Nigeria where South Korea was given the first right of refusal in two of the exploration blocks for which state-owned ONGC Videsh Ltd (OVL) had emerged as front-runners "has proved that we have to be geared to take economic development projects along with bids for exploration," the official said.

During talks with senior company and government representatives by the Indian delegation, led by Petroleum Secretary SC Tripathi, it has emerged "that South Korea and China are cornering most of the opportunities as they are aggressively pushing ahead with proposals for socio-economic development projects also," the official said.

"While looking for opportunities at the full integrated value chain in the petroleum sector, we will have to look at other economic sectors, which poses a challenge," admitted the official.

Currently dominated by multinationals, African countries are in the process of bringing about changes in rules to allow for greater opportunities to local entrepreneurs and new global partners to ensure greater development in the region with energy as the main tool.

India sees in the changes an opportunity that needs to be tapped sooner rather than later.

MALI

Landlocked Mali Seeks more Oil and Gas Exploration

The West African country, Mali says it wants its “open for business” mat for new oil and gas exploration investment to become “well worn”.

Addressing the African Downunder conference in Perth September 12, Mali's director of AUREP (the Government agency in charge of petroleum exploration promotion) Mamadou Simpara, said four petroleum blocks were immediately available for oil and gas exploration.

“We are hopeful that Mali's increasing mining and petroleum activity will generate a higher level of international interest in this acreage than has historically been the case,” Simpara said.

“The tenements - Blocks 15, 16, 17 and 18 - are generally to the southwest with one on the eastern perimeter but all are contained within the five key sedimentary basins,” he said.

“Once assigned, the blocks will be in addition to the 10 blocks already assigned, plus two applied for and being assigned, and two applied for and being reviewed - so Mali's petroleum sector is lifting, and lifting rapidly.

“Australian companies have become an integral part of this expression of confidence in Mali's oil and gas industry by signing a range of agreements with the Mali Government - and we would welcome further significant Australian participation.”

Simpara said Mali's political stability and its legal and regulatory framework, were favorable for investment in the country's oil and mining sectors - with either commodity offering upside because of the extent of under-explored provinces in Mali.

Perth-based Sphere Investments, which has iron ore interests in neighboring Mauritania - is due to commence an oil and gas exploration program in Mali shortly, with exploration team leaders arriving in Mali to start the work programs.

ASX-listed and Perth-based petroleum explorer, Baraka Petroleum Limited, is just completing its first seismic and evaluation work program in Mali and is currently preparing its second program across its five blocks in the Taoudeni Basin.

SOUTH AFRICA

SA's Oil, Gas Industry to get Technology Face-Lift

The Petroleum Oil and Gas Corporation of South Africa (PetroSA) on September 27 announced a joint venture with Petrobras, its Brazilian counterpart, to advance technology between both countries. The petrol giants made the announcement at the 18th World Petroleum Congress in Sandton. The joint venture centered on areas of oil and gas, developing a business relationship and focusing on areas of competitive advantage of companies.

The state owned PetroSA is regarded as an industry leader in gas and liquids technology. It continues to empower and facilitate the participation of more blacks into the gas and oil industry through equity employment and Black Economic Empowerment. The company believes the current venture with Petrobras will go a long way in enhancing efforts to enable the broader South African society to benefit from the deal.

Petrobras is coming to the table with lots of experience in deep water exploration and ethanol production, among other expertise. The company's technical capabilities in exploration, production, downstream, gas and management at various forms is expected to transform the South African industry in reaching its goals in becoming a global player. The company also has stakes in four African countries, Nigeria, Angola, Tanzania and Libya.

This is the first time in the 72-year history of the WPC that the tri-annual congress has been held in Africa and the Southern African International Oil and Gas Exhibition, which is running in parallel. The Congress focuses on global issues, with a particular emphasis on Africa and environmental and social responsibility.

The participants include high-level government and industry delegations from the Councils 65 member countries, together with participants from many non-member countries, more than 500 speakers, 2,000 executives, 250 students and 400 journalists are part of the event.

NIGERIA

Nigeria’s Oil Communities Seek Gas Flares End by 2006

Voices of dissent appear to herald moves by oil multinationals to end gas flaring in the Niger Delta area in three years time, with several of the oil communities preferring a 2006 date.

One of the oil majors, Shell Petroleum Development Company (SPDC), recently shifted its date to end the problematic gas flaring to 2009 ending from the earlier proposed 2008 date.

The latest claim by Oilwatch Africa, a network of environmental human rights groups, revealed that most oil communities in the region are pushing for an end to gas flares not later than 2006.

According to the Manager of Oilwatch Africa and Co-ordinator of Pan-Niger Delta Action Council (PANDAC), Isaac Osuoka, “the Associated Gas Re-injection Act of September 28, 1979 compels every company producing oil and gas in Nigeria to submit preliminary programs for gas re-injection and detailed plans for implementation of gas re-injection. In our interaction with them (oil communities), they are of the view that gas flaring in the Niger Delta should stop in 2006.”

He said the oil communities complain that, “if the oil companies meant well for us, 20 years was enough for them to put out every gas flare,” pointing out that they were expected to submit their gas flare out plan to government by 1980.

Osuoka, however, explained that why the local communities insist on 2006 is the fact that the law attempts to control gas flaring but on the other hand encourage gas re-injection.

“I think the oil communities have a right to demand a stop to gas flaring in 2006. The phenomenon of gas flaring is widespread in the rural oil communities. By throwing up 2006, they are in the main saying that the provision of the Act is not being complied with.”

He further stated that, “as an organization, neither Oilwatch Africa nor PANDAC thinks there is further justification for even limited and restrictive permit of gas flaring beyond 2006, considering its negative environmental impact in the oil region.”

SPDC’s Corporate External Affairs Manager, Don Boham, said recently in Port Harcourt that it was no longer possible for the Anglo-Dutch oil and gas major to end flaring in 2008.

“Gas flaring from our relevant flow stations will not be eliminated until the end of 2009,” he said, although the company made a commitment in 1996 to end continuous flaring of associated gas by 2008, with the Federal Government subsequently adopting the date as a flares-down target. This necessitated embarking on a major integrated plan to collect and put to economic use the gas otherwise flared form Shell’s network of 73 flow stations.

This, according to the company’s spokesman, also entailed a commitment not to develop any new oil fields without “a clear plan for the utilization of the associated gas from such fields.”

RUSSIA

BASF, E.ON and Gazprom Sign Agreement on Gas Pipeline through the Baltic

OAO Gazprom, BASF AG and E.ON AG have signed a basic agreement on the construction of the North European Gas Pipeline (NEGP) through the Baltic Sea. The parties to the agreement intend to set up the North European Gas Pipeline Company as a joint German-Russian venture, with Gazprom holding 51 % and BASF and E.ON each 24.5 %.

At the signing of the agreement, President Putin of Russia and Chancellor Schröder of Germany stressed the strategic importance of the project for the further development of German-Russian relations in the energy sector.

Germany is today Gazprom's largest export market. The NEGP gives Gazprom as the world's leading gas producer a further supply route to this still growing market and, in addition, improves its position as a reliable sup-plier in Germany and western Europe. As a result of the NEGP, Germany gains a direct link to Russia's huge gas reserves. This helps to cover the rising demand for imports in Germany and other European countries and thus reinforces their security of supply. E.ON and BASF will also procure new gas volumes via the NEGP, to which the pipeline systems of WINGAS and E.ON Ruhrgas in Germany will be linked. Consequently, they will enhance their gas procurement, which is marked by growing international competition.

The NEGP will run from Vyborg on Russia's Baltic coast to Germany's Bal-tic coast, the Greifswald region being provisionally earmarked as landfall. The route through the Baltic is being optimized according to technical and economic criteria. Preliminary investigations have already been carried out into the seabed structure. The pipeline will be over 1,200 km long. It is planned to be commissioned in 2010, initially consisting of a single pipeline with an annual transmission capacity of approx. 27.5 billion m³. The project envisages laying a second pipeline and doubling the transmission capacity to approx. 55 billion m³ per annum. The total investment for the twin-pipeline project exceeds €4 billion.

With this agreement, BASF and E.ON are implementing their respective memorandum of understanding signed bilaterally with Gazprom. The aim is to conclude detailed contracts for implementing the NEGP project in the coming months. Gazprom will already start building the land section of the gas pipeline this autumn.

Hydro to Build a Plant at Russia's Shtokman Gas Field

The Norway-based Hydro Company plans to contribute to the liquefied gas plant project at the Shtokman natural gas field in the Russian part of the Barents Sea, the deputy head of the company said September 13.

Hydro intends to buy a 20% stake in the Shtokman project, Bengt Lie Hansen told an international conference on oil and gas field development in the Russian Arctic area and on the continent shelf of the CIS (Commonwealth of Independent States). He called the Shtokman field a driving force in the development of the Arctic shelf.

Hansen said the company would like to develop the fields, build LNG plants and supply resources to the United States. He expects gas production at the deposit to start in 2010 and reach ultimate capacity between 2011 and 2012.

LNG will be exported to the United States and Europe. The Shtokman deposit has the capacity to provide 25% of total natural gas supplies to the United States and can later export gas to Europe, Hansen said.

ONGC Team finds Gas Reserves off Sakhalin

US oil major Exxon Mobil, which is developing oil and gas fields off Russia’s eastern island of Sakhalin, has found extra 560 million barrels to add to reserves, a news agency reported.

Prime-Tass news agency quoted Russia’s resources minister Yuri Trutnev as saying Exxon had asked the government to boost its Sakhalin-1 license territory and grant new reserves without calling a new tender. “Our specialists have now to analyze whether the new reserves are part of the (Exxon’s) Chaivo field or not. If they are not part of it, we’ll have to call a tender,” said Trutnev.

Exxon and its partners in the consortium, which include Japan’s Sodeco, Russia’s state oil firm Rosneft and India’s ONGC, were not immediately available for comment.

The discovery of reserves, which represent around a quarter of already confirmed reserves of the project of 2.3 billion barrels, would be a boost for the project ahead of its planned start up next month. Exxon wants to launch production at Sakhalin-1 in Oct. with plans to start first crude oil exports next year and reach peak output of 250,000 barrels per day in late 2006.

Sakhalin-2 Oil and Gas Project Reaps Benefits of Productive Summer

Despite challenges, great strides have been made over the summer construction period toward completion of the mammoth oil and gas project Sakhalin-2, headed by Royal Dutch/Shell, Lloyds List reported.

As the summer construction season comes to an end in the eastern waters off Sakhalin Island, there has been rapid progress on installing key structures to begin year-round oil and gas production over the next two years. One of the world’s largest integrated oil and gas projects, Sakhalin-2, has made good progress with the concrete platform structures installed this summer. But the revelation of huge cost overruns and delays to laying the pipelines has placed a shadow over these early successes.

Sakhalin Energy Investment is developing more than 1 billion barrels of oil and 500 billion cubic meters of gas resources in two large fields off eastern Russia.

Back in July, Sakhalin Energy revealed a doubling in project costs to $20 billion for all operations to 2014 and delays to first oil and gas production. A raft of issues affects the budget and schedule. Contractor costs have increased for both Russian and international companies, equipment prices have risen and marine vessel leasing rates have jumped higher.

One of the biggest problems is Sakhalin Energy’s issues with the pipelines. Installation work for the offshore section of pipeline has been delayed for environmental considerations and the pipework needs to be re-routed to avoid a whale breeding area. There are also challenges for the construction of onshore pipelines with several rivers and difficult terrain to be crossed.

The Shell-led group is building a platform for the Piltun Astokhskoye oil field and another for the Lunskoye gas-condensate field, plus it is installing a network of offshore and onshore pipelines to link these fields to process centers and export terminals.

The first sections of the two platforms, the concrete gravity-base structures, have been towed to their location and installed.

The Lunskoye Alpha structure was the first to be lowered to the seabed and was followed by the Piltun Bravo platform’s concrete structure. The topsides for these platforms are under construction and due to be lowered on to the substructures next summer. After the Lunskoye concrete gravity base structure was deployed, David Greer, Sakhalin Energy’s deputy chief executive, said: “This particular achievement is a great example of ingenuity. The structure was towed from Vostochny to Lunskoye, we successfully placed the anchors, stabilized the structure and enabled it to be gracefully lowered to the seabed.”

The 103,000 ton substructure is now sitting on the seabed over Lunskoye with only 20 meters of its four 56 meter-high shafts remaining over the water. The concrete gravity-base structure was floated out from the purpose-built dock into Vostochny Bay in Promorsky Krai on June 14 and the tow operation began two days later.

Three ocean tugs escorted by an offshore support vessel and a guard vessel towed the structure through the La Perouse strait to the Lunskoye field, a journey of 1,765 kilometers.

The Lunskoye CGBS consists of a base caisson and four shafts topped by cylindrical steel deck legs that will support the topsides once installed. The base is 105 meters long, 88 meters wide and 13.5 meters thick, and the shafts are 56 meters high, giving the structure a total height of 69.5 meters.

The Piltun B structure is a similar design and was built at the same base in Vostochny. The overall platform will have a production capacity of 70,000 barrels of oil and 100 million cubic feet of gas per day and is due to begin pumping out crude in 2007.

Aker Kvaerner Technology was responsible for design and engineering of these substructures, while Finnish firm Quattro Gemini managed their construction.

More than 250 Russian companies and suppliers were used in the building of these CGBS structures, with 80 percent of the overall labor coming from local teams and 92 percent of the project personnel being Russian.

The onshore part of the second development phase is also making progress. This includes construction of an onshore processing centre on the coast close to Lunskoye and 800 km pipelines to the south of the island to an oil terminal and liquefied natural gas production plant.

Sakhalin Energy hopes to begin full year-round production from the second phase in 2007, once the platforms and pipelines have been commissioned. It had hoped to begin LNG exports before the end of 2007, but delays in pipeline construction work have pushed this back into 2008.

Sakhalin Energy is already producing from the first phase of development through the Vityaz production complex on the Astokh field. Shell and its partners Mitsui and Mitsubishi celebrated the 100th crude cargo from the complex last month with 680,000 barrels of oil bound for Japan.

Under this first phase, oil is processed on the Molikpaq drilling and production platform and stored on the Okhafloating storage and off- loading vessel. Due to the harsh weather and ice-bound environment, the complex can only produce crude during the short summer season. Since July 1999, the Vityaz complex has produced more than 60 million barrels and the target for this year is 12 million barrels.

Despite the cost hikes and construction delays, Sakhalin-2 remains a highly profitable project for the partners and is a key part of Shell’s aspirations to double LNG production by the end of this decade.

It is also a target for Russian gas giant Gazprom, which is negotiating a partnership in the project by swapping onshore gas field assets with some of Shell’s equity.

Russia Eager or OVL Participation in Oil and Gas Projects

Russia is keen on India's ONGC Videsh Ltd partnering with its state-owned firms for oil and gas exploration in its territory and third countries, even as Moscow termed New Delhi as its natural ally.

"We have excellent relationship (with India). We have cooperation not only in oil and gas sector but also in other spheres like defense...We are natural allies," Russia's Minister of Industry and Energy Viktor Borisovich Khristenko said September 30.

"(These are) excellent conditions for developing partnerships," said Khristenko, who arrived Sakhalin to witness along with Indian Petroleum Minister Mani Shankar Aiyar the maiden oil and gas production from Sakhalin-I fields, October 1.

He said participation of OVL, the overseas arm of India's Oil and Natural Gas Corp (ONGC), in Sakhalin-I project has been an exceptional experience for the Russians and they welcomed more such ventures.

OVL has 20 per cent stake in the ExxonMobil-operated Sakhalin-I project, which would start producing about 23,000 barrels of oil per day from October 1 and ramp up the production to 250,000 bpd by 2006-end.

"There are enormous opportunities...In far east (Russia) and in third countries. A number of projects involving OVL are being discussed," he said, but declined to give details of the projects.

OVL wants to join hands with either Rosneft or Gazprom for bidding for Sakhlain-3 project and Timan Pechora fields. Officials said it also wants to join Rosneft in Kazakhstan's Kurmangazy oilfield and purchase part of Yuganskneftegaz, the erstwhile firm of Russian oil major Yukos, which Rosneft acquired few months ago.

Timan-Pechora may hold in-place oil reserves of 4.9 billion tonne of oil equivalent. OVL is also considering participation in the two large oil fields-Trebs and Titova, with estimated reserves of up to 1.25 billion barrels of oil equivalent, and some smaller blocks in the middle of the Pechora Sea.

Aiyar would initiate discussions with Russian authorities on Indian participation in six oil and gas pipeline projects, officials said.

Sakhalin-1 Project to Produce First Oil, Gas

The Sakhalin-1 oil and gas project operated by Exxon Neftegaz Limited (ENL) will start producing the first crude and gas October 1.

ENL said the Yastreb (Hawk) platform on the northeastern coast of the island will begin to pump hydrocarbons from the Chayvo field on the shelf of the Sea of Okhotsk. Ten inclined 8 to 11-km long wells have been drilled to the deposit. At the same time the Orlan platform is drilling 20 vertical wells to the reserves.

Exxon Neftegaz said it had completed on September 30 connecting its pipelines to Russian trunklines going from Sakhalin to Komsomolsk-on-Amur and De-Kastri settlement in Khabarovsk region.

Sakhalin-1 annual production is to comprise 12.5 million tons. South Korea is building five tankers on Russian orders with a displacement of 100 thousand tons each for transportation of the crude.

ENL Vice-President Mark Hackney told Tass natural gas from Chayvo will be used mostly for the needs of Khabarovsk region. By 2009 gas sales to the region will reach three billion cubic meters a year.

Besides Chayvo, Exxon Neftegaz and its partners are developing the Odoptu and Arkutun-Dagi fields in the northeastern shelf of Sakhalin. Potential reserves of the fields are estimated at 307 million tons of oil and 485 billion cubic meters of gas. Capital investments into the development of all fields of the Sakhalin-1 project are estimated at over 12 billion US dollars.

Production of hydrocarbons has been going on since 1999 at the Piltun-Astokh oil field of the Sakhalin-2 project. The Molikpak platform of the Sakhalin Energy Company is engaged in production. From 2008 five platforms will extract oil and gas on the Sakhalin shelf. The island will annually deliver to the world market over 20 million tons of oil and 9.6 million tons of liquefied natural gas.

KRGYZSTAN

New Oil and Gas Field Discovered in Kyrgyzstan

Mezon TV (Osh) reports that a new gas and oil field has been discovered at Lot 238 not far from the town of Kochkor-Ata in southern Kazakhstan (about 50 kilometers from Dzhalalabad).

According to Timur Murataliyev, Senior Deputy Chairman of Kyrgyz Oil and Gaz, 100-120 tons of raw oil will be produced there every day.

"As for gas, some additional surveys are needed before we know for sure. At this point, I can only surmise that daily production will amount to between 10 and 20 tons," Murataliyev said.

All necessary equipment has already been installed. Oil and gas production in the field regarded as one of the largest in the country will begin in the near future.

TURKMENISTAN

Turkmenistan Buys Oil & Gas Pipes for $18 million

Turkmenistan will buy pipes for its oil & gas industry for the amount of $18 million. A decree by Saparmurat Niyazov, president of Turkmenistan, directed at "accelerated geologic drilling works for oil and gas survey and construction of exploration and operational oil and gas wells" said a Turkmenistani government press service September 20.

As per the document, the state concern "Turkmengas" can conclude a contract with the "Pipe Metallurgic Company - Kazakhstan" LLC, a branch of the "Pipe Metallurgic Company" OJSC (Russia,) for the supply of steel casing and tubing pipes in the quantity of 12,240.33 tons.

The supply of the pipes is suggested to take place from November, 2005, to February, 2006, for the following customers: the state concern "Turkmengas" in the quantity of 4,034 tons, the state concern "Turkmenneft" in the quantity of 6,266.23 tons, and for the state corporation "Turkmengeologia" - 1,940.1 tons.

The government press service has explained that the cost of the contract will be paid at the expense of the state concerns "Turkmengas" and "Turkmenneft."

IRAN

Energy Bringing Beijing and Tehran Closer Together

Iran is in the midst of a geopolitical transformation that has the potential to inflame the world's most volatile and unpredictable region. An integral part of this transformation is the nurturing of bilateral relations with countries sharing similar geopolitical interests and a strong resentment for perceived U.S. hegemony -- China is such a country.

Already China's second largest supplier of oil behind only Saudi Arabia, Iran is ideally positioned to play a central role in China's overall energy policy moving forward. Some energy observers predict that China will consume more oil than the U.S. and 75 per cent of all new global oil production by 2015. This, as global demand for oil continues to grow at a pace not seen since 1980.

Fueling the global demand for oil, liquefied natural gas (LNG) and other forms of energy is an energy starved China. Imports of crude reached 130 million tonnes in 2005, up from a record 122 million tonnes in 2004. Most experts agree that China's domestic oil and LNG supplies will be insufficient to meet its rising demand for energy in the very near future. As a result, Iran, one of the leading producers of oil and LNG in the world, has become a natural partner for China.

But unanswered questions remain concerning the budding relationship. What will Iran's ultimate role be in China's overall global strategy? How will the relationship evolve beyond energy? And could regional instability in the Middle East result from the China-Iran bilateral alliance?

Unsettling signs of energy-related stress are already evident throughout China, threatening the country's plans for sustained growth.

Increased energy demands in China have caused oil supply shortages and inflation, crippling China's vibrant Guangdong and Yunnan provinces. In Shenzhen City alone, over 128 gas stations were closed in August, as prices continued to spiral upward. Major cities such as Beijing and Shanghai have also felt the effect of gas shortages. In Heilongjiang Province, long gas lines have brought back memories of America's gas shortages of the 1970's with frustrated Chinese consumers wondering when it will all end. The frequent shortages have prompted some Chinese to ask if a nationwide energy crisis is unavoidable.

Complicating China's energy woes, the Daqing oil field, one of the country's most mature oil fields producing 900,000 barrels per day (bpd), saw its production decline by 5 per cent in 2004. Recently, the Chinese government hired foreign energy firms to try and extend the life of its second largest field, Liaohe in northeastern China, as fears mount that the field will dry up in only a few short years.

These serious energy developments have led Beijing to increase its ties to Tehran. Recent statements released by the Chinese Academy of Social Sciences support the view that China will increase its oil dependence on the Middle East in the years to come, "It is an unarguable fact that China's dependence on Middle East oil is increasing. Henceforth, the Middle East will be the most important supply source of international oil for China."

Gavin Thompson, of British oil consulting firm Wood Mackenzie, recently noted, "China will never be able to satisfy its oil demand through foreign acquisitions. They are getting 55 to 60 per cent of their oil imports from the Middle East. In the future, that proportion will only increase."

The number of energy-related deals over the past year between Beijing and Tehran have been staggering. In late October 2004, a mega contract was signed by China oil giant Sinopec and Iran for an estimated $100 billion for the shipment of 250 million tonnes of LNG and 150,000 bpd of crude oil over a 25-year period. A subsequent $100 billion LNG deal is on the near horizon bringing the total investment package to an incredible $200 billion.

Adding to this impressive array of bilateral energy deals, China's state oil trader Zhuhai Zhenrong Corp. agreed in 2004 to buy over 110 million tonnes of LNG from Iran over a 25-year period for $20 billion. Both countries also announced a joint tanker venture for the transport of LNG to China. Finally, a deal was struck in late 2004 between the two countries to build a refinery in Iran to handle 360,000 bpd of gas condensates. The project, which is expected to be completed in 2007 or 2008, is being financed by state-owned investment company China International Investment Trust Company (CITIC).

According to the Oil and Gas Journal, Iran is the second largest oil producer in the world with its 32 oil fields containing approximately 125.8 billion barrels (bb) of proven oil reserves, or 10% of the world's total. In 2004, the country's proven oil reserves increased to 132 bb after new oil discoveries were made in the Kushk and Hosseineih oil fields located in the Iranian province of Khuzestan.

To meet global energy demand, Iran is pushing forward with plans to increase oil and LNG production by investing $50 billion in its energy sector over the next several years. This level of investment is essential for the country's economic growth, since oil proceeds account for 40 to 50 per cent of government revenues.

Some energy experts believe that Iran could increase its crude capacity to meet the specific energy needs of China, but not without an enormous struggle. Iran has not exceeded 3.9 million bpd production levels since 1978/79. Plans announced by Iran's Ministry of Oil to produce 5 million bpd by 2009 and 7 million bpd by 2024 have been termed "ambitious" by many in the oil industry.

In addition to oil, Iran possesses the world's second largest reserves of LNG behind only Russia with 940 trillion cubic feet (Tcf) in proven natural gas reserves. Iran's LNG production is expected to rise to 206 billion cubic meters (cm) in 2005; 342 cm in 2010; and 519 cm in 2025. Making opportunities for increased China-Iran bilateral energy cooperation even more plausible is the fact that many of Iran's most promising gas fields remain unexploited. This presents China with enormous investment opportunities and new areas for cooperative projects, further cementing the bilateral relationship.

Gal Luft, executive director of the Institute for the Analysis of Global Security recently noted, "Without a comprehensive strategy designed to prevent China from becoming an oil consumer on par with the U.S., a superpower collision is in the cards."

Without question, closer energy ties between Beijing and Tehran will reduce Washington's leverage on matters of economic, military and nuclear importance. Taken separately; China and Iran are formidable regional powers. However, taken together, they become a regional and global force. Add to the equation Chinese and Iranian joint cooperation in organizations such as the Shanghai Cooperation Organization (SCO), and confrontation with the U.S. becomes a distinct possibility.

China now sees Iran as its main strategic ally in the Middle East. Recent statements made by Chinese officials to world bodies such as the United Nations, European Union and International Atomic Energy Agency (IAEA) defending Iran's uranium-enrichment activities prove that a closer relationship is rapidly evolving. "I don't think IAEA talks will be helpful to bring the issue to the [security] council. The council has too many things on its table. Why should we add to this," said China's UN Ambassador Wang Guangya.

For those countries looking to challenge U.S. influence in the Middle East, U.S. Energy Secretary Spencer Abraham has a clear message, "Energy security is a fundamental component of [U.S.] national security. Military force will be an increasingly important prerequisite to safeguard the flow of foreign oil." Simply stated, any independent or coordinated threat to the U.S. oil supply originating in the Middle East will be met by an overwhelming U.S. military response.

Will Iran become the "poison-tipped spike on the red dragon's tail," intoxicated by the prospect of reviving the past glory of the Persian Empire? Evidence is mounting that China is trying to cultivate a unique strategic relationship with Iran, while also expanding its influence throughout the Middle East.

Chinese President Hu Jintao has publicly stated that energy will be high on his agenda for his trip to Washington in September. President Bush should take this opportunity to propose a future U.S.-China led energy summit, inviting countries such as Japan, Germany, Great Britain and Russia to participate. This would be a constructive way to address the challenges presented by global oil dependency. It is in best interests of the U.S., China and the world to address the growing global energy crisis before the time for negotiation passes.

QATAR

$14 Billion Qatar Gas Contracts

Qatar has awarded contracts to US, Japanese and French firms for engineering, procurement and construction works as part of a $14bn gas project. The project is expected to supply gas principally to the US for 25 years starting 2008. The companies involved include US-based J Ray McDermott Middle East, and a joint venture between Japan-based Chiyoda Corporation and France-based Technip France.

Mitsui to Take Part in large LNG Project in Qatar

Major Japanese trader Mitsui Co. will participate in a liquefied natural gas (LNG) production project in Qatar, a project that will boast one of the world's largest output capacities for a single production facility. Mitsui has reached a basic agreement to acquire a 1.5 percent interest in the project, which is being planned by Qatar's state-run oil company, Qatar Petroleum, and US firm ConocoPhillips, the Nikkei business daily here reported September 27.

The Qatargas 3 project, slated to start production in 2009, will have an annual LNG capacity of 7.8 million tons, according to the daily. It will take gas produced from Qatar's giant North Field in the Arabian Gulf and liquefy it at a plant to be constructed at Ras Laffan Industrial City.

Mitsui will purchase up to 10 million barrels a year of condensate -- the material produced when drilling for natural gas -- for a period of 13 years and ship it to Asian nations, mainly Japan. With ConocoPhillips planning to export the project's LNG output to the US market, Mitsui is continuing negotiations so that it can also receive some of the liquefied gas.

The total cost of the undertaking is estimated at USD 5.5 billion, and based on its stake, Mitsui will likely need to guarantee about USD 82 million in funds provided to the project.

Qatar, which has the world's largest single gas field, has been maneuvering aggressively to boost LNG production. Its total output is expected to reach 77 million tons in the 2010s, making it the largest producer of LNG, surpassing Indonesia and Malaysia.

RasGas Awards Two New LNG Trains to Produce 110,000bpd of Condensate

The two liquefied natural gas (LNG) trains for whose construction RasGas 3 awarded multi-billion dollar contracts in September, will additionally produce 110,000 barrels per day (bpd) of condensate.

Besides, some 47,000 bpd, or 1.6 million tonnes per annum, of Liquefied Petroleum Gas (LPG) will be produced by the two trains that are to be the largest in the world with a capacity each of 7.8 million tonnes per annum.

The proposed onshore facilities will take advantage of synergies with existing trains, Dr Ibrahim Al Ibrahim, deputy chairman of RasGas, said.

He said the project was massive by any standards with future potential for ethane and helium recovery as well.

Helium recovered from the two trains (6 and 7) can be supplied to the second Qatar Helium refining plant.

Dr Ibrahim was speaking at the awarding ceremony for the Engineering, Procurement and Construction (EPC) contracts for the two LNG trains (6 and 7), which completes the second phase of LNG expansion at the RasGas site.

The two Trains with a combined capacity of 15.6 million tonnes per annum (MTA) of LNG will bring the total RasGas LNG production to 36.6mtpa.

Ras Laffan Liquefied Natural Gas Company Limited (3), or RasGas 3, contracts to US, Japanese and French firms for the onshore and offshore EPC for the two trains, which are part of an overall LNG project worth a staggering $14bn.

The offshore contract was awarded to J Ray MacDermott Middle East while the onshore contract was awarded to the Chiyoda Corporation and Technip France Joint Venture (CTJV).

The offshore facilities contract involves the construction and installation of two offshore 12 well platforms and two 100 km 38-inch export pipelines to the shore. Each pipeline has an ultimate capability of two billion standard cubic feet per day.

Two thousand major pieces will be used during the construction of Trains 6 and 7 with a site plot area covering 500,000 square meters, equivalent of 100 soccer fields.

32,500 tonnes of structural steel will be used which is enough to build two domed sports stadiums and the number of workers to be deployed on site could run up to 13,000.

YEMEN

SOCO Provides Yemen Exploration Update

SOCO's majority owned subsidiary, Comeco Petroleum, Inc., through which the Company holds a 16.785% net working interest in the East Shabwa Development Area in Yemen ("ESDA"), has announced the commencement of drilling on the Kharir North prospect. The KHA-3-07 well (previously referred to as the KHA 407 prior to the revised well numbering system agreed with the Yemeni authorities) spudded on the 31st of August and is the first well targeting Basement on this prospect.

The KHA-2-17 (previously KHA-406) injector well that spudded on 11th June 2005 is currently being connected to the appropriate facilities prior to commencing a water injectivity test.

Comeco, in which SOCO holds a 58.75% interest, has a 28.57% interest in the ESDA in Block 10 in Yemen. The East Shabwa joint venture is operated by TOTAL Yemen, S.A. (28.57% interest) under a production sharing agreement with the government of Yemen. The other joint venture partners are Occidental Yemen Ltd. (28.57% interest) and Kuwait Foreign Petroleum Exploration Co. (14.29% interest).

Air Products to Provide Liquefaction Process Technology and Equipment for New LNG Plant in Yemen

Air Products (NYSE: APD) announced September 20 that it received an order for two main cryogenic heat exchangers from Yemen LNG Company Ltd. for two liquefied natural gas (LNG) process trains to be built in Bal-Haf, Republic of Yemen. The two heat exchangers will be part of Yemen's first-ever LNG plant.

"Air Products will provide its proprietary propane pre-cooled mixed refrigerant liquefaction process technology with the Split MRTM refrigeration equipment configuration, and an MCR(R) main cryogenic heat exchanger for each train of the facility," said Mark Modjeska, director, LNG for Air Products. The two LNG trains will have a total capacity of 6.7 million metric tons per year of LNG. The target for Train 1 start-up is the end of 2008, with Train 2 coming on line approximately 5 months later.

The shareholders of Yemen LNG Company Ltd. are Total (42.90%), Yemen Gas Company (23.10%), Hunt Oil Company (18%), SK Corporation (10%) and Hyundai Corporation (6%).

A vast majority of the total worldwide baseload LNG production capacity is produced with Air Products' technology. Air Products has designed, manufactured, and exported nearly 75 LNG heat exchangers from its Wilkes-Barre, Pa. facility over the last 30 years.

In support of the LNG industry, Air Products provides process license and key equipment for the heart of the baseload liquefaction process and land-based nitrogen plants for the baseload LNG facility. Upstream, Air Products provides both nitrogen and natural gas dehydration membrane systems for offshore platforms. Downstream, Air Products provides dry inert gas generators for LNG carriers, shipboard membrane nitrogen systems, land-based membrane and cryogenic nitrogen systems, LNG import terminals, and LNG peak shavers.

McIlvaine Company,

Northfield, IL 60093-2743

Tel: 847-784-0012; Fax: 847-784-0061;

E-mail: editor@mcilvainecompany.com;

Web site: www.mcilvainecompany.com