Floating Liquefied Natural Gas (FLNG) business has been witnessing a rapid growth since 2005 and has now emerged as one of the leading destinations for most of the oil and gas companies. Building on its strategic advantages of low cost, low price and ability to capitalize stranded reserves, most companies and countries are opting for FLNG. Latest developments in the technology are leading to construction of a large number of fleets (or barges) that can sail (or be towed) to offshore gas discoveries, extract gas, liquefy it and offload the LNG to tankers for shipping to end-markets.

To ensure that the LNG companies don't fall behind in the race to invest in FLNG and to ensure that their investments are diverted to right locations, LNGReports have come up with a brand new report on FLNG -- "Global FLNG (Floating LNG) Development and Outlook to 2015- The new investment Destination."

In addition to introducing different technologies, different FLNG facilities and components, the report allows the identification of the prospects of market through planned investments and capacity outlooks and enables the identification of key markets, companies, technologies and facilities being used in the global and regional FLNG industry.

The report includes:

· An in-depth introduction to FLNG and micro, macro economic drivers for FLNG industry

· Description of all prospective developments over 2010 to 2015 on a country to country basis for 11 countries

· Detailed information on all the 23 active and planned floating LNG terminals including operator, ownership, construction cost and period, capacity, location and expected commencement date

· 10 key operating and constructing companies along with their FLNG operation and market structures are discussed in detail.

Det Norske Says LNG to Dominate Ship Fueling Within 40 Years

Liquefied natural gas will become the dominant fuel source for all merchant ships within 40 years as environmental pressures force owners to use cleaner burning fuel, the world’s fourth-largest vessel classifier said.

Ships must cut emissions of sulfur oxides, a pollutant said to cause acid rain, to 0.5 percent by 2020 from 4.5 percent today under rules from the International Maritime Organization. In more environmentally sensitive areas, the upper limit drops to 0.1 percent by 2015 from 1 percent today.

“Environmental requirements aren’t going to get any less strict,” Lars Petter Blikom, segment director for LNG at Det Norske Veritas, a company that verifies ships are seaworthy, said in a Nov. 16 interview in London. “That’s just going to make gas even more compelling and there’s no other realistic option.”

LNG, chilled to 1/600th of its gaseous size, costs $397.28 a metric ton, according to Spectron. Bunker fuel oil with a sulfur content of 4.5 percent and a viscosity of 380 centistokes costs $475.26 a ton, according to data compiled by Bloomberg from 25 ports. Nitrogen oxides trigger reactions that lead to the formation of ozone, a pollutant that irritates eyes and lungs.

By 2020, a majority of owners will ask for LNG fuel tanks every time they place an order for new vessels to be built, Blikom said.

Orders worth about $46.1 billion have been placed for all kinds of ships so far this year, more than double 2009’s $28.2 billion, and below the $164.5 billion in 2007, according to Clarkson Plc, the world’s largest shipbroker. Changing specifications so that ships burn LNG will add about 10 percent to construction costs, Blikom said.

As well as generating more revenue for yards including Hyundai Heavy Industries, the world’s largest, the switchover will bolster demand for LNG as a fuel.

Ships will burn 200 million to 250 million tons of heavy fuel oil this year, the Southampton, England-based International Bunker Association estimates. Based on the higher end of that range, a switchover of the entire shipping fleet to LNG refueling would create demand for 360 million tons of oil- equivalent of the liquefied gas, Per Wiggo Richardsen, Det Norske Veritas’s director of communications, said. That would be “much more than double” existing demand for the liquefied form of the fuel, he said.

“The shipping industry has been the main demand source for the lowest quality oil products” and environmental legislation will halt that situation, Blikom said.

Most likely, LNG will be shipped to ocean-going vessels by specialist barges or small tankers from land-based LNG storage tanks in a method similar to how heavy fuel is distributed today, Blikom said.

LNG cuts carbon emissions from shipping by about 25 percent, sulfur oxides by almost 100 percent, and nitrogen oxides by 85 percent, Blikom said. As well as fitting out new carriers to run on LNG, it’s possible to retrofit existing vessels to use the fuel, he said. Nitrogen oxides pollution is also being curtailed under the International Maritime Organization rules. The shipping industry will face pressure to cut its carbon emissions too, Blikom said.

Waertsilae OYG, the world’s biggest engine maker, said November 12 that 10 percent of ships calling at Emission Control Areas, where the 0.1 percent limit will apply soonest, will be running on LNG by 2015. That would represent a tenfold increase in vessels using the fuel, it said.

Excluding ships that are employed in the LNG trade already, Det Norske Veritas has certified 21 out of the 22 merchant ships that currently burn the fuel. Including vessels already operating in the LNG industry, there are about 100 carriers that use the fuel for propulsion today, according to Waertsilae.

AMERICAS

U.S.

MARAD Okays Bienville Regas Terminal Offshore Alabama

Maritime Administrator David T. Matsuda has signed the Record of Decision approving the deepwater port application submitted by TORP Terminal LP for a license to own, construct and operate the Bienville Offshore Energy Terminal, an LNG regasification facility located in the Gulf of Mexico, 63 miles south of Dauphin Island, Alabama, in a water depth of 425 feet.

"This is another important step in making the Bienville Offshore Energy Terminal a reality," said Joe Berno, CEO of TORP Terminal LP. "In addition to the Bienville Terminal's innovative technical solution, we plan to transform the way that regasification capacity has been offered to the industry. Our goal is to provide the lowest annual cost of holding regasification capacity in the United States."

According to Lars Odeskaug, CEO of TORP LNG, "This Record of Decision proves that smaller terminal developers can introduce innovative solutions, both technically and commercially, to offer long-term access to the world's largest natural gas market at very attractive terms. Similarly, we have developed the EasyLNG technology, which is designed for use in protected waters and offers the lowest regasification rates for small to medium volumes. We have already received interest from clients in South America, Asia and Europe that would benefit from this technology."

The Bienville Offshore Energy Terminal will use the award-winning HiLoad technology and a floating regasification unit with no permanent offshore structures. The Terminal will also utilize closed-loop ambient air vaporization, which is a preferred solution of the Environmental Protection Agency (EPA), National Oceanic and Atmospheric Administration (NOAA), and environmental groups. The Terminal will have a peak LNG sendout capacity of 1.4 Bcf per day and will be able to accommodate any LNG carrier without modification to the incoming vessel.

The Bienville Terminal's location in the northeastern Gulf provides ready access to markets in the U.S. Southeast, as well as those in the middle and eastern portions of the nation. Other benefits include the proximity to underground natural gas storage facilities and existing pipelines to Florida while avoiding the congestion along the Texas-Louisiana border.

Morgan Stanley, Cheniere Sign Sabine Pass Liquefaction MOU

Cheniere Energy Partners, L.P. (Cheniere Partners) announced November 8 that its subsidiary, Sabine Pass Liquefaction, LLC ("Sabine"), has entered into a non-binding memorandum of understanding (MOU) with Morgan Stanley Capital Group Inc. in connection with the potential acquisition by Morgan Stanley of certain import capacity and approximately twenty percent of a proposed 7.0 million tonnes per annum (mtpa) of LNG liquefaction capacity at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana.

Consistent with the MOU, definitive agreements would provide Morgan Stanley the ability to export or import 1.7 mtpa of LNG from the proposed facility. The arrangement is subject to negotiation and execution of definitive agreements and certain other customary conditions to closing for transactions of this type including but not limited to the receipt by each party of requisite internal approvals, the receipt of necessary regulatory approvals and Sabine making a final investment decision to construct the liquefaction facilities. The MOU does not represent a final and binding agreement with respect to its subject matter.

"This is a significant development for our liquefaction project at Sabine Pass," said Charif Souki, Chairman and CEO of Cheniere Partners. "I am pleased with all of the progress we have made to date and look forward to continuing discussions with Morgan Stanley and with additional customers in order to advance with our project."

Cheniere Partners owns 100 percent of the Sabine Pass LNG terminal located in western Cameron Parish, Louisiana on the Sabine Pass Channel. The terminal has sendout capacity of 4.0 Bcf/d and storage capacity of 16.9 Bcfe.

As currently contemplated, the liquefaction project would be designed and permitted for up to four modular LNG trains, each with a peak processing capacity of up to approximately 0.7 Bcf/d of natural gas and an average liquefaction capacity of approximately 3.5 mtpa. The initial project phase is anticipated to include two modular trains and the capacity to process on average approximately 1.2 Bcf/d of pipeline quality natural gas.

Cheniere Partners intends to enter into contracts for at least 0.5 Bcf/d of natural gas liquefaction capacity per train in support of reaching a final investment decision regarding the development of the project. It believes that the time and cost required to develop its proposed liquefaction project would be materially lessened by Sabine Pass LNG's existing large acreage and infrastructure (docks, LNG storage tanks, power generation assets and pipeline connections).

Cheniere Partners will fund development costs incurred during the assessment of this project using existing funds. The partnership will contemplate making a final investment decision to commence construction of the liquefaction facilities upon, among other things, achieving regulatory approval and entering into acceptable commercial and financing arrangements. It anticipates LNG export could commence as early as 2015.

Senators Want to Halt Funds for Weavers Cove LNG Project Review

In the continuing fight against a proposed liquefied natural gas terminal in Mount Hope Bay, U.S. senators from Rhode Island and Massachusetts have signaled their intent to prohibit using federal money to review the project proposal.

Without the money, it would be impossible for the Federal Energy Regulatory Commission to assess the application from Weaver's Cove Energy for the floating terminal. The senators' aim is to kill a plan that has been widely opposed in Rhode Island and Massachusetts on grounds that it would damage the environment, disrupt boating and pose a safety hazard. Weaver's Cove maintains that the project is safe and that shipments can be made without having a negative effect on Narragansett and Mount Hope bays.

The idea of withholding money for the review was first put forward months ago by Massachusetts Representatives Barney Frank and James McGovern, who proposed language to that effect in a House appropriations bill for the U.S. Department of Energy.

The relevant section would be unequivocal, stating "no funds made available by the act may be used to take any action to authorize the construction of any liquefied natural gas terminal or its infrastructure to be located within five miles of the city of Fall River, Massachusetts, or to authorize vessels carrying liquefied natural gas to serve such terminal."

Senators Jack Reed, Sheldon Whitehouse, Scott Brown and John Kerry sent a letter in November to the Senate Appropriations Subcommittee on Energy and Water Development urging that it insert similar language into a companion bill.

"Both of our states will be negatively impacted by this proposed LNG terminal and we strongly encourage you to include language in the final appropriations bill that would prohibit the use of federal funds to support this ill-advised project," the senators wrote in the November 3 letter.

At a public forum on the Weaver's Cove project in September, Whitehouse cautioned that the chances of the Senate passing an appropriations bill with that language included were slim.

Meanwhile, the Federal Energy Regulatory Commission is developing a draft Environmental Impact Statement for the LNG project.

Oregon Court Decision May Complicate Bradford Landing LNG Efforts

The Oregon Court of Appeals upheld a decision by state authorities to overturn local zoning approvals for the Bradwood Landing liquefied natural gas terminal, proposed for a site 20 miles east of Astoria on the Columbia River.

Though Bradwood's backers have already declared bankruptcy and abandoned their efforts, opponents worry that another entity could resurrect the project by purchasing the development rights out of bankruptcy.

More significantly, the appeals court's decision on what constitutes salmon protection could play into ongoing efforts to develop LNG terminals in Warrenton and Coos Bay.

Twice in the last two years, the state Land Use Board of Appeals sent Clatsop County's zoning approval for the Bradwood Landing terminal back for reconsideration. LUBA asked the county to justify how it determined the terminal would be a small- to medium-size industrial facility, versus a large one, and thus consistent with the county's land-use plan.

LUBA also said the county had adopted too narrow a definition of the word "protect" when it determined the project met the requirement to protect traditional fishing areas and endangered species habitat from incompatible development.

During the first week of November, the state appeals court affirmed both findings. Opponents of the projects hope the latter of the two will undermine efforts to develop LNG terminals in Coos Bay and Warrenton.

Both projects involve marine dredging for the terminals and include long pipelines that cross rivers and streams -- potentially impacting salmon habitat.

The court's decision said "mitigation" efforts weren't the same thing as "protection." Protection, it said, "means inhibiting development that causes significant adverse impacts on the protected resource."

"If there was any hope of selling the Bradwood license, that's now gone," said Brett VandenHeuvel, executive director of Columbia Riverkeeper, which originally appealed Clatsop County's zoning changes to LUBA.

VandenHeuvel was also optimistic that the decision would be applied elsewhere.

"It brings into the question some of the mitigation that Oregon LNG and Coos Bay are relying on," he said, and could impact the Department of Environmental Quality's analysis of whether the proposed LNG terminals and related pipelines protect salmon

Cheniere Subsidiary Signs MOU for Sabine Pass Bi-directional Processing Deal

Cheniere Energy Partners, L.P. ("Cheniere Partners") announced November 11 that its subsidiary, Sabine Pass Liquefaction, LLC ("Sabine"), has signed a memorandum of understanding ("MOU") with ENN Energy Trading Co., Ltd., under which ENN Energy Trading intends to contract 1.5 million tonnes per annum ("mtpa") of bi-directional LNG processing capacity at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana.

Under the MOU, ENN Energy Trading and Sabine have agreed to proceed with negotiations of definitive agreements for ENN Energy Trading to contract capacity for a primary term of 20 years with mutually agreed extension terms, subject to certain conditions precedent, including but not limited to Sabine's receipt of regulatory approvals and making a final investment decision to construct the liquefaction facilities, and ENN Energy Trading reaching a final investment decision to construct an LNG receiving terminal.

ENN Energy Trading, a subsidiary of ENN Energy Holdings Ltd. ("ENN Energy") (formerly known as XinAo Gas) is one of the largest independently owned natural gas operators in the People's Republic of China. Through its natural gas distribution business ENN Energy has obtained rights for operating piped natural gas in more than 80 cities in 15 provinces across China with a combined connectable urban population of approximately 45 million.

ENN Energy is currently connected to approximately five million residential, commercial and industrial customers and is seeking to secure new gas supply in order to connect to additional customers residing in the provinces in which it has rights to distribute gas. ENN Energy is anticipating an estimated thirty percent increase in sales growth over the next several years. ENN Energy plans to build as many as two LNG receiving terminals in China and is in the process of obtaining approvals from the administrative authorities for its identified sites.

El Paso Sells Pipeline, LNG Terminal Stakes to Affiliate, El Paso Pipeline Partners for $1.13 Billion

El Paso Corp., owner of the longest U.S. natural-gas pipeline network, agreed to sell stakes in two interstate pipeline systems and a liquefied natural gas terminal in Georgia to an affiliate for $1.13 billion.

The transaction would give El Paso Pipeline Partners LP full ownership of terminal-owner Southern LNG Co. and El Paso Elba Express Co. as well as a 60 percent stake in Southern Natural Gas Co., the partnership said in a statement November 15.

Elba Express and Southern Natural Gas are pipeline systems serving the southeast. Southern LNG owns the Elba Island terminal near Savannah, Georgia, which can handle as much as 1.8 billion cubic feet of gas a day from tankers that deliver it in liquefied form.

“It’s a little bit bigger transaction than expected,” Carl Kirst, a Houston-based analyst for BMO Capital Markets, said in an interview. He rates the shares at “outperform” and owns none. “It’s a good transaction price for El Paso, but not so steep that the partnership doesn’t find it immediately cash accretive.”

The deal, expected to close this month, is its third and largest purchase this year from El Paso Corp., bringing the total to more than $2.4 billion, El Paso Pipeline Partners said. El Paso Corp., based in Houston, owns 52 percent of the pipeline partnership and controls it through ownership of its general partner.

El Paso Pipelines is paying for the deal with $415 million in cash and may finance the rest of it through a combination of debt and equity offerings and a promissory note to El Paso Corp.

The purchase will immediately add to the partnership’s cash flow, Jim Yardley, chief executive officer of El Paso Pipelines, said in the statement. The partnership’s management will recommend raising the quarterly cash payout to unit holders to 44 cents from 41 cents, according to the statement.

El Paso has said it would sell assets to the partnership to raise cash for expansion.

Fall River LNG Facility Opponent, “Save the Bay” Appeals Case to Investors

A major opponent of the proposed Fall River LNG facility is appealing to Boston’s Fidelity Investments, State Street Corp. and Wellington Management to pressure Hess Corp. to drop its controversial development plan.

Providence-based Save the Bay said it sent letters to Hess’ major shareholders - including Fidelity, State Street and Wellington - as part of an effort to finally kill the Fall River project.

The LNG facility, first proposed in 2003 and bitterly opposed by many Massachusetts and Rhode Island residents, is still seeking federal and state permits to construct a storage-tank yard along Fall River’s waterfront.

“The plan is grinding ahead,” said Jonathan Stone, executive director of Save the Bay.

Hess has already “wasted tens of millions of dollars” pushing the plan, harming shareholders and others in the process, Stone said.

The group is also reaching out to Wall Street analysts to convince them that the Fall River project is a bad investment for Hess.

A Hess spokesman could not immediately be reached for comment.

Under the latest Hess plan, an LNG tanker would steam through Narragansett Bay, under the Newport and Mount Home bridges, and then anchor in Mount Hope Bay. LNG would then be pumped, via underwater pipelines, about 4.25 miles to a land-based storage facility in Fall River.

San Bruno Blast Brings an End to California LNG Development

There is no doubt that Pacific Gas & Electric Co. has acted at least somewhat more responsibly in the wake of the September natural gas pipeline explosion in San Bruno than BP did after its springtime offshore oil platform disaster in the Gulf of Mexico.

No one had to jawbone PG&E to set up a $100 million fund for victims the way President Barack Obama had to hammer on BP executives before they agreed to compensate victims of their blast. No one forced PG&E's offer to buy up all the damaged homes at a premium price.

But no matter how well PG&E behaves now (and it has yet to clean up its pipeline maintenance act), one long-term consequence of San Bruno will almost certainly be the death of any and all plans to bring more liquefied natural gas to California.

So far, at least six proposals to build LNG receiving terminals along the California coast have been killed or mothballed over the past five years, and a total of eight have died since 1980.

The only West Coast receiving facility capable of placing LNG in use here is Sempra Energy's Costa Azul facility near Ensenada in the Mexican state of Baja California Norte.

Because of demand for LNG in countries like Japan and South Korea very little LNG figures to enter California through Costa Azul in the near future.

Even before San Bruno, proposals to build other receiving terminals in Humboldt County, Ventura County; Long Beach and near Camp Pendleton in San Diego County had all died or atrophied. But plans for two terminals in Oregon at Astoria and Coos Bay are still alive.

Enter the pipeline explosion. Each Oregon proposal would require about 100 miles of gas pipeline to run from its coastal location to an existing PG&E line that now carries gas to California from the Canadian province of Alberta.

In recent months, those lines have become the most contentious parts of the Oregon LNG plans. The pipeline from the possible Bradwood plant at Astoria would have to cross part of Washington and that state's authorities have issued several unfavorable reports on its environmental implications.

The pipeline from the putative Coos Bay facility, known as Jordan Cove, would cross the Coast Range before joining the existing PG&E line near Roseburg in central Oregon. It drew loud protests from farmers and ranchers even before San Bruno.

Part of the opposition in Oregon arises because of a study by the state's utility regulators which found that about three-fourths of any LNG arriving in Oregon would end up in California.

This, of course, would mean added cost to California consumers, whose gas prices would rise as the costs of building plants, pipelines and tankers were tacked onto the price of the gas itself.

Both Oregon and California regulators would most likely go along with this happily -- if there were a need for the gas. But as early as six years ago, a federal Energy Information Agency report indicated no gas shortage was likely in California until 2030 at the earliest.

Large-scale development of natural gas from shale deposits in Texas, Oklahoma, Wyoming and Colorado since then has both driven down the price of gas and pushed back the likely date of any shortage by a minimum of 20 years. So the question arises: Why build plants and pipelines today in anticipation of a problem that might exist in 40 years, or might never arise if America begins using more renewable energy sources?

One reason is that there is now foreign demand for some of that gas from shale. In fact, owners of several East Coast and Canadian LNG terminals have lately proposed converting them into gasification facilities from which American gas could be exported.

But doing that in Oregon would still require pipeline construction.

And the questions about PG&E's maintenance of its existing pipeline network that arose immediately after the San Bruno disaster and still remain; have done nothing but harden opposition to building anything that will tie into PG&E's network.

All this makes it virtually certain that LNG development of any kind will get nowhere on the West Coast for many years to come, a development that should be welcomed by every Californian who uses natural gas for heat or cooking.

Macquarie Bank, Freeport to Build $2 Bln Texas LNG Export Terminal

Liquefied natural gas terminal developer Freeport LNG and Macquarie Bank have agreed to build an export plant in Texas to send U.S.-produced gas overseas just as U.S. inventories hit record highs.

The plant, which would be able to export 1.4 billion cubic feet per day of gas by 2015, will cost about $2 billion and will be built on the site of Freeport LNG's existing import terminal, the company said November 21. Freeport LNG will operate the plant, with Macquarie contributing to development costs. The companies will share in the upside from marketing the LNG, according to a statement. Macquarie and Freeport plan to jointly market half of the export plant's capacity, with the other half being offered to Freeport's existing import customers, Dow Chemical (DOW.N) and ConocoPhillips.

The Freeport LNG plant is the second planned LNG export facility in the United States to be announced this year. In June, Cheniere Energy (LNG.A) unveiled plans to build the first LNG export plant in 40 years on the site of its Sabine Pass import facility. Cheniere also plans to produce and export LNG by 2015. The construction of LNG export facilities is an about-face for the U.S. natural gas market, where several import facilities were built in anticipation that the United States would become a major LNG importer in the coming decades. Instead, a boom in unconventional gas production, including shale gas, has flooded the U.S. natural gas market with supply, while demand has flagged, pushing U.S natural gas inventories to a record high this month and pressuring prices.

Most U.S. import terminals have sat idle over the past three years as shippers look to higher-paying markets in Europe, Asia and South America to send their cargoes. Freeport has been underused since it began operations in June 2008. "While forecasts that natural gas prices will remain relatively low in the U.S. do not bode well for import terminals, the price differential has opened up an opportunity to make the U.S. a leading exporter of natural gas," the companies' statement said.

Freeport and Macquarie are looking to supply their LNG primarily to Asia, where LNG prices have risen above European and U.S. gas prices this year, offering a handsome premium for shippers across the globe. Project officials have visited Asia in recent days to drum up interest in the project. Generally, an LNG production plant does not reach a final investment decision until most of its capacity is sold under long-term contracts. "We see a lot of growth in demand in Asia and a lot of the counterparties are looking for diversity of supply," Nicholas O'Kane, senior managing director and global head of Macquarie Group's Energy Markets Division, said in an interview with Reuters on November 22. ["We are not discounting Europe, but at the moment, Japan,

Taiwan, Korea, China, even some of the Southeast Asian nations -- the first shipments will be made out to Asia."

CUBA

China’s CNPC Bln Cuba Cienfuegos Refinery Expansion Project to Include $1.3 Bln LNG Terminal

A unit of China National Petroleum Corp (CNPC) is set to begin in 2011 a $6-billion expansion project at Cuba's Cienfuegos refinery in one of the biggest investments ever on the communist-led island, a source close to the project said November 22.

The blockbuster deal will be financed mostly by China's Eximbank and backed by financial guarantees in the form of oil from Venezuela, Cuba's close socialist ally and leading trade partner, the source said.

State-owned CNPC's Haunqiu Contracting and Engineering Corp is expected to start the project in the first quarter with completion planned for the end of 2013.

The Italian unit of French oilfield service company Technip will do design and engineering for the project and assist in construction.

The expansion will increase the capacity of the Soviet era refinery 155 miles southeast of Havana to 150,000 barrels per day from 65,000.

But it will also include construction of a liquefied natural gas terminal with capacity to process 2 million tons of gas annually, and a 150 megawatt electricity generation plant.

"It is one of the biggest investments in the history of Cuba. It's a minimum of $4.5 billion just for the refinery and another $1.3 billion for the LNG terminal," an executive involved with the project told Reuters.

ASIA

AUSTRALIA

WorleyParsons Wins $580 Mln Queensland Curtis LNG Contract

WorleyParsons has been appointed as the detailed engineering and procurement services contractor for the upstream gas field facilities and related infrastructure associated with QGC's Queensland Curtis LNG Project.

The potential revenue for WorleyParsons from this contract is in excess of $580 million.

WorleyParsons' CEO, Mr John Grill, said, "I am extremely pleased that WorleyParsons has secured this award, providing us with the opportunity to partner with BG and QGC on this cutting-edge coal seam gas project."

BG Finalizes $15 Bln Investment Decision to Advance Queensland Curtis LNG

BG Group has announced that it has taken the final investment decision approving implementation of the first phase of the Queensland Curtis Liquefied Natural Gas project ("QCLNG") following receipt of Australian Federal and State Government environmental approvals.

The first phase of QCLNG encompasses the development of a two-train liquefaction plant on Curtis Island near Gladstone in Queensland together with the associated upstream and pipeline facilities. BG Group will progress development and construction of QCLNG with immediate effect.

QCLNG will be operated by BG Group's Australian subsidiary, QGC Pty Limited ("QGC"). The first phase of the liquefaction plant will consist of two LNG trains with a combined capacity of 8.5 million tonnes per annum (mtpa). Over the next four years (2011-2014), BG Group plans to invest approximately US$15 billion in developing the liquefaction plant and related wells, field facilities and pipelines. There is also significant potential to expand QCLNG, with the construction of a third LNG train already covered by existing State and Federal approvals.

First LNG exports are planned to commence from 2014, underpinned by agreements in Chile, China, Japan and Singapore for the purchase of up to 9.5 mtpa of LNG. Total gross discovered coal seam gas reserves and resources presently amount to an estimated 17.3 trillion cubic feet (tcf) - equivalent to more than 2.9 billion barrels of oil equivalent - with 2P (proved plus probable) reserves now estimated at 7 tcf.

BG Group Chief Executive Frank Chapman said: "In early 2008, we announced our first investment in Australia. Today, less than three years later, we are announcing our decision to develop the world's first LNG plant to be supplied by coal seam gas and the foundation project at the centre of a major new Australian export industry."

"I believe the speed of our transition from country entry through major resource maturation to project sanction reinforces BG Group's reputation for advancing innovative and complex gas chain projects within challenging timeframes, as previously demonstrated in Trinidad and Tobago and in Egypt. This rapid progress is also testament to our strategic global marketing capabilities: QCLNG is anchored in customer agreements across the world's largest LNG markets for the sale of up to 9.5 million tonnes of LNG per annum."

"Today's decision represents the realization of a pivotal strategic objective for BG Group - to further the globalization of our LNG business by establishing a new and material source of equity LNG in the Asia-Pacific arena. Today's sanction is also a significant milestone on the road to delivery of the Group's growth agenda over the decade ahead."

QGC Managing Director Catherine Tanna said: "Our decision to proceed follows nearly three years of rigorous regulatory and public review and discussions with more than 4,000 individuals, landholders, indigenous groups, conservationists, industry associations, regional councils and government agencies. Their contributions have played a key role in shaping regulations intended to ensure that this project is good for the environment, good for people, and good for Australia."

BG Group's decision to sanction the development of the first phase of QCLNG completes the final condition required for implementation of the Group's agreements with the China National Offshore Oil Corporation ("CNOOC"), signed in March 2010. Under those agreements, CNOOC will:

· purchase 3.6 mtpa of LNG for a period of 20 years from the start-up of QCLNG

· purchase 5% of BG Group's interests in certain tenements in the Walloons Fairway of the Surat Basin

· jointly participate with BG Group in a consortium to construct two LNG ships in China that would be owned by the consortium

· become 10% equity investor in the first LNG train in the initial phase of the liquefaction plant.

Separately, the decision to sanction the project satisfies one of the conditions precedent associated with the proposed agreements with Tokyo Gas Co. Ltd., announced in March 2010, under which Tokyo Gas will:

· purchase 1.2 mtpa of LNG for 20 years from 2015

· purchase 1.25% of BG Group's interests in certain tenements in the Walloons Fairway of the Surat Basin

· become 2.5% equity investor in the second LNG train of the liquefaction plant.

Final notices to proceed will be issued to the main contractors appointed for the development of the first phase of QCLNG. Those contractors include:

· Bechtel Oil and Gas, Inc., for the engineering, procurement and construction of the liquefaction plant

· WorleyParsons, for gas field facilities and infrastructure development

· MCJV (a joint venture between McConnell Dowell Constructors (Aust.) Pty Ltd and Consolidated Contractors Company), for the transmission pipeline network.

Natural gas in coals (coal seam gas) occurs when the coal is formed deep underground by a process of heating and compressing plant matter. The gas is trapped in coal seams (typically 300-600 meters underground) by water pressure. The coal seam gas is extracted via wells which are drilled down through the coal seams. The water is pumped out, and the natural gas is released from the coal. The gas is then processed to remove water and piped to a compression plant for injection into gas transmission pipelines.

Inpex, Total Release Tender for Ichthys Processing Facility

The Ichthys Project (INPEX Browse, Ltd. 76%, Operator, and Total E&P Australia 24%) has released the Invitation to Tender (ITT) for the semi-submersible Central Processing Facility (CPF) to be located at the Ichthys Gas Field (WA-37-R) in the Timor Sea, approximately 200 kilometers off the northwest coast of Australia.

President Director Australia, Inpex Corp., Seiya Ito said the release of the ITT for the CPF's engineering, procurement and construction (EPC) contract was a significant step toward the delivery of the world-class Ichthys LNG project.

"The issue of the invitations to tender is the culmination of many months of hard work by the project team for what is an exciting, complex and challenging endeavor," Ito said. "Today, INPEX and Total have confirmed the real potential of Ichthys to significantly build the capacity of the Australian LNG industry to play a role in global energy security."

ITTs for additional packages will be issued before the end of the year, including for the:

· Floating Production Storage and Offloading (FPSO) vessel

· Umbilical, risers and flowlines (URF)

· Gas export pipeline (GEP)

· Subsea production system (SPS)

The GEP will transport the gas from the field to Darwin, Northern Territory, where the onshore liquefied natural gas (LNG) plant is to be located. Details of the packages for the onshore gas processing facilities in Darwin will be issued subsequently.

Ito said no one is underestimating the challenges of developing a project of the size and scope of Ichthys.

"Nor should we underestimate the opportunities the project holds for the Northern Territory and Australian economies as we develop a resource of more than 12 trillion cubic feet of gas and more than 500 million barrels of high-value condensate."

Ito said Inpex's portfolio of investments meant its share of production in Australia made it the country's fifth largest oil and gas producer and that Ichthys would establish the company as one of the leading petroleum producers in the nation. "The release of the ITTs demonstrates our commitment to delivering our flagship Ichthys Project and to the long-term growth of the Company, and confirms we are moving forward toward a final investment decision (FID), as scheduled for Q4 2011."

The CPF will be one of the largest semi-submersible platforms in the world. Its main function is to gather the gas from the various subsea production wells and undertake preliminary processing of the gas to remove water and extract high-value condensate, a natural gas liquid hydrocarbon present in the gas stream. The supporting FPSO will have a condensate storage capacity of 1.14 million barrels.

Ito said a significant number of the world's leading engineering and construction companies had prequalified for the ITTs.

Under the Ichthys Project's Australian Industry Participation Plan (AIP), bidding companies have a commitment to creating full, fair and reasonable opportunity for Australian suppliers. This AIP commitment provides opportunities for Australian fabrication yards, equipment suppliers and manufacturers to bid for work from the Project's sub-packages in what will be a truly global supply chain.

The Ichthys Project is a Joint Venture between Inpex Browse Ltd (76%, the Operator) and Total E&P Australia (24%). Gas from the Ichthys Field, in the Browse Basin offshore of Western Australia, will undergo preliminary processing offshore to remove water and and extract condensate. The gas will then be exported to the onshore processing facilities in Darwin via an 885km subsea pipeline. The Ichthys Project is expected to produce 8.4 million tonnes of LNG and 1.6 million tonnes of LPG per annum, along with 100,000 barrels of condensate per day at peak.

Australia Pacific CSG-to-LNG Project Get Queensland Government Approval

Australia Pacific LNG Pty Limited on November 9 achieved a significant milestone with the Queensland Coordinator-General's approval for its coal seam gas (CSG) to liquefied natural gas project. Australia Pacific LNG is a 50:50 CSG to LNG joint venture between Origin and ConocoPhillips.

Approval, subject to the strict conditions outlined in the Coordinator-General's report, has been granted for the development of the gas field occurring progressively over a 30-year period; a 450km transmission pipeline and an LNG facility on Curtis Island.

Australia Pacific LNG Project Director, Page Maxson, said gaining the approval was a significant milestone in realizing the potential benefits of the project and ensuring appropriate management of the potential environmental impacts.

Maxson said, "The stringent conditions contained in the Coordinator-General's report, including detailed on-going monitoring and reporting requirements, should give the community confidence that the project will meet the high standards required during construction and operation.

"The project will form part of a burgeoning world-scale, long-term industry in Queensland, utilizing Australia Pacific LNG's substantial coal seam gas resources in the Surat and Bowen Basins," said Maxson. Compliance with the Coordinator-General's conditions will be independently audited, with Australia Pacific LNG also required to provide an annual environmental report.

The Coordinator-General's report recognizes the comprehensive nature of the Australia Pacific LNG EIS. The EIS included an assessment of the cumulative impacts of all existing projects proposed for the region, including other CSG to LNG projects and an undertaking to develop and implement a comprehensive biodiversity protection strategy.

To support the EIS consultation process, Australia Pacific LNG met with more than 6,000 stakeholders including landowners and non-government organizations during an 18-month period. Thirty-six formal submissions were received from government agencies and the public, all of which were considered as part of the Coordinator General's approval.

Maxson said, "The Australia Pacific LNG project will deliver a range of significant opportunities and benefits for many local communities and we look forward to continued, positive engagement and being an integral part of these communities for decades to come."

The Queensland Coordinator-General's report will now be provided to the Commonwealth Government for further consideration and approval. Commonwealth approval is a further step in gaining the necessary regulatory approvals for the project to proceed.

In April 2009, the Queensland Coordinator-General declared the Australia Pacific LNG Project a "significant project" under the State Development and Public Organization Act (1971) and the EIS process commenced.

The draft EIS Terms of Reference were made available for public comment by the Coordinator-General from August to October 2009 and were subsequently finalized. The draft EIS for the Project was lodged with the Queensland Government on 29 January 2010 and the EIS was released by the Coordinator-General on March 29, 2010 for public comment and examination by government advisory agencies. The Project has also been referred to the Commonwealth Government for consideration under the Environment Protection and Biodiversity Conservation Act (1999).

Australia Pacific LNG Pty Limited is a 50:50 incorporated joint venture between Origin Energy Limited and ConocoPhillips which combines Origin's 13 and ConocoPhillips' 25 years of CSG experience, as well as ConocoPhillips' 40 years experience in operating and developing LNG facilities. Australia Pacific LNG is already producing almost 40 percent of Australia's total CSG production to meet domestic market requirements. Australia Pacific LNG holds the largest CSG reserves in Australia. Australia Pacific LNG's Project stretches from the Surat and Bowen Basins along a 450km pipeline to a site at Laird Point on Curtis Island off Gladstone. Origin is Australia's largest integrated energy company and ConocoPhillips is a leader in the development of LNG Projects internationally including the existing plant in Darwin, Australia.

Shell to Divest Woodside Stake for $3.3 bln

Shell has entered an agreement to sell part of its stake in Woodside to equity investors for $3.3 billion.

Shell's subsidiary, Shell Energy Holdings Australia Limited (SEHAL), has entered into an underwriting agreement with UBS AG, for the sale of 78.34 million shares in Woodside, representing 29.18% of its interest in Woodside and 10.0% of the issued capital in Woodside at a price of A$42.23 per share. Upon completion of the sale, SEHAL will continue to own a 24.27% interest in Woodside. As part of this transaction, SEHAL has committed to retain its remaining shares in Woodside for a minimum of one year, with limited exceptions, including a sale to a strategic third party of an interest greater than 3% in Woodside provided the purchaser agrees to be bound by the same escrow restrictions to which SEHAL is subject or in pursuit of an acceptance to a bona fide takeover offer for Woodside.

Shell CEO, Peter Voser, said, "Shell is an industry leader in global LNG, and will be a leading investor in Australia for years to come. Our Australian LNG portfolio has developed rapidly in recent years, with exploration success around Gorgon and Prelude, and our entry into coal bed methane plays through the joint acquisition of Arrow Energy. This is a strong platform for new growth."

Voser continued, "Our stake in Woodside has been an important part of Shell's portfolio in Australia for many years. We are looking forward to working with Woodside on important new growth projects where we are partners. However, with Shell's recent portfolio progress in Australia, our world-wide push to simplify the company and to improve our capital efficiency, we will increasingly focus our investment in Australia through direct interests in assets and joint ventures, rather than indirect stakes. We will manage our remaining position in Woodside over time in the context of our global portfolio."

Shell Australia's Country Chair, Ann Pickard, concluded, "These are exciting times for the LNG industry in Australia, and for Shell. We are unlocking new LNG supplies from our portfolio, and working closely with Woodside on further growth projects where we will remain with them as a partner. Shell's directly-owned Australia LNG capacity is around 2.7 mtpa today, and is forecast to more than double to some 6.5 mtpa by 2015, as Gorgon comes on line. Looking beyond 2015, we see significant further growth potential from pre-FID options. Our directly-owned assets in Australia could add a further 10 mpta for Shell beyond 2015 towards a total of 16 mtpa. Shell will be a major player in Australia for years to come, and all of this will help to further consolidate Australia's position as a leader in energy and resource supply for the Asia Pacific region."

Australia Approves Giant $5.0 Bln Shell Floating LNG Plant

Australia has given environmental approval for Shell to install a revolutionary floating liquefied natural gas plant which is set to become the world's longest vessel.

Environment Minister Tony Burke gave the green light with conditions aimed at protecting the area, off sparsely populated north-western Australia, from damage including oil spills.

''This is a large-scale project that is using world-first technology. We can't risk getting it wrong, so I have set very strict conditions to help ensure our precious marine environment will be protected,'' he said.

The under-design structure, the length of five football pitches, will cool gas from Shell's Prelude field into liquid for shipping. The energy source is on track to become a major industry in Australia.

Shell said the floating ship-shaped structure; which will reportedly cost US$5.0 billion, would be some 480 meters (1,600 feet) long, 75 meters wide and weigh about 600,000 metric tons.

''Deploying our floating LNG technology reduces the project's cost and environmental footprint,'' said Ann Pickard, chairwoman of the Anglo-Dutch company's Australian wing.

''It removes the need for offshore compression platforms, long pipelines to shore, nearshore works such as dredging and jetty construction, and onshore development such as building roads, laydown areas and accommodation.''

A Shell spokeswoman said talks on a production license were ''progressing well'' and a final investment decision was expected to be made next year, with the platform scheduled to open in 2016.

She confirmed comments by senior Shell official Malcolm Brinded, who said last year that the plant would be ''significantly the largest vessel in the world when it's constructed''.

The platform, nearly 50 percent longer than the USS Enterprise aircraft carrier, is being designed by France's Technip and will be built by South Korea's Samsung, who are contracted for ''multiple'' editions.

Woodside's $13 Bln Pluto LNG Plant Likely Delayed by Labor Strikes and Design Issues

Woodside Petroleum Ltd's $13 billion Pluto liquefied natural gas plant in northwestern Australia will likely be delayed a few months, pushed back by repeated labor strikes and design problems.

Industry analysts said the company, which is set to release the findings of a cost and schedule review for the 4.3 million tonne per annum (mtpa) project before the end of the month, is likely to push back the target for its first LNG cargo by one to six months.

Woodside had previously targeted February 2011 for the start-up of the plant and March 2011 for first LNG production, and most analysts still expect that Pluto will begin production around the middle of 2011.

"I don't think it will be a substantial delay... it's all but finished except for some minor details," Peter Strachan with Stock Analysis in Perth said.

Pluto was 94 per cent complete by the end of September, according to Woodside, but the project has been plagued with rolling labour strikes which analysts blame for the likely delay in first LNG production.

Adding to its labor woes, Pluto's flare towers did not meet Woodside's own specifications, forcing the company to rebuild some portions of the towers ahead of cyclone season.

Although most industry analysts are targeting first LNG production in May, June or July, some analysts see potential for initial LNG production to slip into the fourth quarter.

"The risk is very much to the later side," analyst at Macquarie Bank in Sydney, who targets first LNG for July 2011, Adrian Wood said.

LNG delivery from the project could be pushed back to the beginning of the fourth quarter in a worst-case scenario, Mr Wood said.

In a further indication that Woodside is expecting LNG production to be delayed, the company is looking to buy cargoes from Petronas to cover its first deliveries, according to media reports.

Woodside, the operator and 90 per cent stakeholder in Pluto, has 15-year sales agreements with Kansai Electric and Tokyo Gas, that are each five per cent stakeholders.

Despite setbacks to staying on schedule, Pluto may still be on track to become the fastest developed LNG project from discovery of the gas field in 2005 to first LNG, according to the company's website.

Delays and cost overruns are routine in the oil and gas industry.

"This is not unusual. All LNG start-ups are complex and it's not surprising if the first delivery slips a bit,", analyst with Tri-Zen Capital in Singapore Tony Regan said.

Pluto is just one of at least 10 Australian LNG projects that are planned for build through 2017 in an attempt to supply rapidly growing Asian demand for the fuel.

Woodside is considering plans to add another five mtpa at the Pluto site if it can secure gas supplies and is also developing the seven mtpa Browse LNG project, also located in northwest Australia.

CHINA

Air Products Air Separation Unit Goes Onstream at CNOOC Plant

Air Products on November 11 announced China's first air separation unit (ASU) facility that uses liquefied natural gas cold energy to produce industrial gases has been brought onstream. Located in Putian, the plant is a joint venture with CNOOC Energy Technology & Services Limited and is capable of producing over 600 tons per day of liquid oxygen, nitrogen and argon to supply the fast growing industrial gases market in Fujian Province, especially in the Xiamen, Putian, Fuzhou triangle.

Air Products and ASU technology, formed the joint venture in 2007 with CNOOC Energy Technology & Services Limited, a wholly owned subsidiary of China National Offshore Oil Corporation (CNOOC), one of the largest state-owned oil companies and a leading offshore oil and gas producer in the country.

The first of its kind in China, the ASU plant is designed to liquefy air at low temperatures by using cold energy released during the LNG re-gasification process to produce industrial gas products. The plant brings tremendous environmental and energy efficiency benefits compared to conventional processes as this ASU plant consumes approximately 50 percent less electricity by using the LNG cold energy to aid in liquefaction and to produce chilled glycol. The chilled glycol displaces the cooling water utility previously used for air compression in the ASU plant, thereby also conserving water resources. Additionally, the use of LNG cold energy technology decreases carbon dioxide emissions by reducing electrical use in operation of the ASU.

"The use of cold energy significantly reduces power consumption in the industrial gas production process and helps protect the environment. This facility supports the Chinese government's mission to save energy and reduce emissions by maximizing the utilization of natural gas, and also Air Products' overall sustainability goals of operational productivity improvements to reduce energy consumption and emissions," said Bob Dixon, senior vice president and general manager of Global Merchant Gases at Air Products. "We are deeply honored to partner with CNOOC in making a reality this first-ever use of LNG cold energy integrated with an ASU in China. We appreciate the strong support of the CNOOC leadership, and that of the Fujian Province and Putian City governments for this project."

INDIA

Petronet LNG Terminal Capacity to be Doubled at Kochi

Petronet LNG Ltd, a consortium promoted by state-owned energy firms, has decided to double the capacity of a proposed liquefied natural gas terminal at Puthuvypu, near Kochi in Kerala, to 5 million tonnes (mt).

Petroleum secretary S. Sunderasan said the Petronet board, which met in Kochi on November 21, decided to enhance capacity by taking investment in the terminal to Rs.4,000 crore. The terminal is expected to be commissioned by March 2012. The firm had tied up a 1.5-tonne LNG supply agreement with ExxonMobil Australia and is in talks with other LNG suppliers, said A.K. Balyan, Petronet’s managing director and chief operating officer.

"In principle, we have decided to give the go ahead to expand the capacity of the LNG terminal at Cochin (Kochi) from 2.5 million tonnes to 5 million tonnes and the final proposal in this regard will be considered for approval at the next board meeting," said Sundareshan.

He also revealed the new investments that will be made in the State.

"Over 10,000 crore (rupees) is going to be invested in Kerala. About 3,700 crore on the LNG terminal which is coming up in Cochin, about 5,000 crore is going to be invested by Gas Authority of India Limited (GAIL), in the pipeline network that is coming in the State," said Sundareshan.

Sundareshan further added that the Iran-Pakistan pipeline project is being discussed and companies like GAIL and Indian Oil Corporation are in talks with the Government over the matter.

GAIL (India) Ltd, Oil and Natural Gas Corp. Ltd, Indian Oil Corp. Ltd and Bharat Petroleum Corp. Ltd each hold 12.5% in Petronet, while 10% is held by GDF International Co. Ltd, 5.2% by the Asian Development Bank and 34.8% by the public.

INDONESIA

Foster Wheeler Wins Indonesia FLNG Project

Foster Wheeler AG announced November 2 that its Global Engineering and Construction Group has been awarded a contract by Perusahaan Gas Negara (PGN) a leading state owned enterprise and public listed company in the natural gas business in Indonesia, for the provision of project management consultancy (PMC) services for a new floating LNG receiving terminal (the "Medan Floating LNG Terminal" facility) to be built in Medan, North Sumatra, Indonesia.

The Foster Wheeler contract value for this project was not disclosed. The contract will be included in the company's third quarter 2010 bookings.

Foster Wheeler's scope of work includes technical assistance through the initial phase of the development of the project, conceptual design of the terminal, basic design of the subsea and onshore pipeline as well as the preparation and issue of an invitation to bid for engineering, procurement and construction (EPC), EPC bid evaluations, preparation of the EPC contract and support to PGN in EPC contract negotiation. Foster Wheeler will fulfill the role of owner's engineer during the EPC phase of the project through to start-up of the terminal.

"This award constitutes a strong vote of confidence in our project management and technical skills in floating LNG terminals and pipelines," said Umberto della Sala, Chief Executive Officer of Foster Wheeler AG.

KOREA

ABB Wins $58 Mln Contract to Supply Electrical Systems for Samsung LNG Newbuilds

ABB has recently won an order worth $58 million to provide complete power and propulsion systems for six new liquefied natural gas transport vessels to be built by Samsung Heavy Industries (SHI) at its shipyard in South Korea. The order was booked during the third quarter of 2010.

Samsung Heavy Industries is one of the world's leading builders of advanced high-end vessels for the oil and gas industries.

ABB will supply complete electrical systems for the ships; the delivery includes power generation and distribution systems, electric propulsion as well as the propulsion control systems, and related engineering services.

ABB's electric propulsion concept combined with the dual-fuel engines ensures full flexibility to utilize various types of fuels. This flexibility enables the vessel to optimize their fuel selection, energy efficiency and fuel consumption while achieving the lowest possible emission levels when compared to traditional diesel mechanical systems.

Scheduled to be commissioned from 2012 through 2015, the ships will be used by several major oil and gas industry end customers to transport liquefied natural gas. The global demand for LNG is increasing as a low emission, clean energy source for use in industrial, commercial and residential applications.

SINGAPORE

Singapore LNG Corp to Expand Terminal Capacity with Third Tank

Singapore LNG Corp. is raising the capacity of a liquefied natural gas terminal it is building to meet growing domestic demand and interest from related businesses, the company's chief executive said November 2.

Singapore will add a third tank with a capacity of 180,000 cubic meters, raising the terminal's total capacity to 6 million metric tons a year from the previously planned 3.5 million tons, CEO Neil McGregor said, confirming a statement released earlier by the government.

The third tank will be ready as part of the overall construction of the terminal, which is planned to open in 2013.

The main reason for the construction of a third tank is the expected rise in Singapore's domestic demand for LNG, driven primarily by higher industrial growth, McGregor said.

Singapore's LNG demand is expected to rise to 2 million tons a year starting in 2013 compared with an earlier estimate of 1.5 million tons, the senior minister of state for trade, industry and education said.

At least half of the 16 major companies in Singapore that trade or produce liquefied natural gas have approached Singapore LNG Corp. about using the terminal for trading activities such as storage, McGregor said.

"We've been in discussions with a lot of the trading houses and producers" as well as financial institutions, he said, without naming the companies.

"Although it's not a primary driver, in the interim we'd like to start a trading business," McGregor said, adding the company would seek a "commercial return for any trading option."

Earlier this year, Russia's Gazprom (GAZP.RS) opened a Singapore office to oversee its LNG trade operations in the region, while ConocoPhillips (COP) decided to relocate its global LNG headquarters to Singapore from Houston.

The third tank gives Singapore the option to buy from more than one supplier once its exclusive contract with BG Group PLC ends. BG's exclusivity will end once it reaches shipments of 3 million tons a year to Singapore or until 2023, whichever comes first.

Singapore LNG Corp. isn't in talks with any other suppliers at this time, McGregor said.

Although cheaper natural gas is piped into Singapore from Malaysia and Indonesia, both countries are expected to become net importers of the fuel, which may drive up prices, McGregor said. With supplies of LNG rising in countries such as Qatar, Russia and Australia, LNG is the "best economic alternative," he said.

EUROPE / AFRICA / MIDDLE EAST

EQUATORIAL GUINEA

Equatorial Guinea has enough Natural-gas for Second LNG Production Plant

Equatorial Guinea has enough natural-gas reserves for a second liquefied gas production plant, according to a presidential adviser.

“The discovered gas resources in Equatorial Guinea are estimated at approximately 9 trillion cubic feet,” Domingo Mba Esono, the nation’s presidential adviser on mines and hydrocarbons, said at a conference in London . “The first project, Train 1, was sanctioned with 3 trillion.”

Equatorial Guinea LNG Holdings Ltd. can expand by adding a second production unit and load its first cargo in 2016, according to Marathon Oil Corp. estimates made last year.

Exploration blocks O, I, R and the Zafiro field will supply the second LNG train, Esono said. Gas supplies from Nigeria and Cameroon may be needed to make the plant commercially viable.

“We are hoping to attract gas from neighboring countries if they don’t find a use for it,” Esono said. Esono said less than half of the country’s gas, from the Alba field, is currently used for commercial purposes.

The Zafiro field burns off 100 million cubic feet of gas each day, with another 44 million wasted at offshore fields. The offshore deposits will cut flaring, or the burning off the fuel as unwanted alongside oil production, to 10 million cubic feet a day by 2013, Esono said.

The 2006 hydrocarbon law prohibits flaring, according to Esono, who couldn’t say when the practice will end. State-owned Sociedad Nacional de Gas, or Sonagas, together with Germany’s E.ON AG, Portugal’s Galp Energia SGPS SA and Spain’s Union Fenosa SA, are planning to develop the local gas industry.

Investment in the country’s oil and gas sector will increase to $45 billion “in the next few years,” Esono said, from about $35 billion now. Equatorial Guinea LNG is a venture between Marathon Oil, Sonagas, Mitsui & Co. and Marubeni Corp.

The plant can produce about 3.4 million tons of LNG each year. All the gas is bought by BG Group Plc under a 17-year agreement that started in 2007.

MOZAMBIQUE

Anadarko Considers Mozambique LNG Project

U.S. oil producer Anadarko Petroleum Corp. (APC) said November 29 that its third major gas discovery off the coast of Mozambique has given it confidence that reserves are big enough to justify a liquefied natural gas project.

Anadarko said an exploration well drilled on the Lagosta prospect in Mozambique's Rovuma Basin had found more than 550 net feet of natural gas pay, although appraisal drilling will be necessary to determine whether gas can be produced commercially.

"We believe the three discoveries announced to date already exceed the resource size threshold necessary to support an LNG development, and we have assigned an integrated project team to begin advancing commercialization options," Anadarko Senior Vice-President of Worldwide Exploration Bob Daniels said.

Large-scale LNG developments typically cost several billion U.S. dollars, and reserves of four trillion cubic feet of natural gas are typically required for each facility, or train, that processes the raw gas and converts into a liquid.

Daniels said the Lagosta well, drilled in waters around 5,000 feet deep, is near the company's two other discoveries offshore Mozambique and "significantly expands this emerging world-class natural gas province."

Drilling at Lagosta is continuing to test a deeper area of the seabed, before the rig is moved to drill another exploration well nearby, Anadarko said in a statement.

Anadarko owns 36.5% of the permit where the discoveries have been made. Other shareholders include units of Japan's Mitsui & Co. and India's Bharat Petroleum Corp. Ltd..

The Lagosta gas find underscores Mozambique's attraction as a place for resources companies to invest, after years off the radar due to a bloody civil war. The country is also in the midst of a mining boom due to vast reserves of coking coal discovered close to its coastline that can potentially be exploited and shipped to fast growing markets in Asia.

RUSSIA

CB&I Wins Shtokman Storage and Loading Facility FEED Contract

CB&I announced November 16 that CB&I Lummus has been awarded a contract for the front-end engineering & design (FEED) services for the Shtokman LNG storage and loading facility at the sea port in Terriberka in the Murmansk region of the Russian Federation.

The sea port is part of the Shtokman Gas-Condensate Field Development Project developed by Gazprom Dobycha Shelf LLC, a fully owned subsidiary of Gazprom JSC. CB&I's contract, which is scheduled for completion in 2011, has been awarded by Giprospetsgas JSC, the project general designer. The value of the contract was not disclosed.

The Shtokman Gas-Condensate Field Development Project consists of the production, treatment, transportation, liquefaction, storage and shipping of natural gas and natural gas liquids from the Shtokman field located 600 km offshore in the Barents Sea, north of Kola Peninsula, Russia. The field has an estimated 3.9 trillion cubic meters of natural gas reserves.

CB&I's project scope includes concept and FEED development of the LNG storage and loading facility, including multiple 160,000 cubic meter full containment LNG storage tanks and the associated process piping and loading facilities. Concept and FEED development will provide the project schedule and cost estimates for the engineering, procurement and construction phase. CB&I will also prepare the Russian design dossier (Proyekt) in accordance with regulatory requirements.

QATAR

Nakilat Shipyard at Ras Laffan to Repair Large LNG Carriers

Nakilat shipyard, which was to be formally inaugurated at Ras Laffan on November 23, will undertake construction of ships up to 120m in length, besides repair and maintenance of very large LNG carriers and range of other vessels.

The 43-hectare ship repair yard, which has been built on reclaimed land, includes facilities for the fabrication of structures for the offshore oil and gas industry and onshore petrochemical and industrial plants.

The shipyard work was undertaken as part of the comprehensive development of Ras Laffan Industrial City (RLC), managed by Qatar Petroleum.

In February 2007, QP appointed Nakilat to manage the design and construction of phases 1 and 2 (major ship repair yard) and undertake various studies relating to the other phases (3, 4 & 5).

Later, Nakilat formed a joint venture with Keppel Offshore & Marine, a global leader in ship conversion and repair as well as a specialized shipbuilder, to operate the new yard.

Under the project’s first phase, facilities have been created for the fabrication of structures for the offshore oil and gas industry, which include jack-up drilling rigs, process modules, decks, jackets, wellhead decks and flare booms. It also involves repair and conversion of very large ships.

The second phase focuses on repair of medium-sized ships, which are in the 20,000dwt to 80,000dwt category.

Under Phase 3, the fabrication and maintenance of offshore structures (and components for onshore petrochemical plant) will be carried out.

Phase 4 involves construction of high value small ships of up to 120m length. The joint venture – Nakilat-Damen Shipyards Qatar (N-DSQ) – is managing this phase.

The JV will manage the construction of high-value ships of up to 120m in length, including commercial, naval and coastguard vessels and luxury yachts.

Phase 5 is focusing on repair of small ships of up to 20,000dwt.

All the above facilities are located in the expanded Ras Laffan Port.

Qatar will be home to a new world-scale marine industry with the formal launching of the Nakilat shipyard at Ras Laffan.

Currently, Qatar has minimal capacity for the repair and conversion of large ships, fabrication of offshore structures, or construction of high value small ships. Qatar’s needs in these sectors are mostly catered to by foreign companies.

Nakilat created a Project Task Force (PTF) to manage the project, with team members from Nakilat, Keppel and QP. The PTF worked on Market Assessments and Feasibility Studies for the remaining phases, in association with leading international consultants in their respective fields.

McIlvaine Company,

Northfield, IL 60093-2743

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

E-mail: editor@mcilvainecompany.com