The exploitation of unconventional energy such as shale gas, coal-bed methane and oil sands is creating abundant energy development opportunities in the U.S. So much gas available is promoting a rapid increase in many new projects such as pipelines, chemical process plants and ethylene crackers. That’s good news for those manufacturing, repairing and servicing gas turbines, centrifugal compressors and micro turbines.

For instance, the LNG import terminal in Dominion Cove Point, MD received its first imports from Algeria in the late seventies. But these days, business has been way down. Only five LNG shipments were received in all of last year. That’s why Dominion gained approval to enable the Chesapeake Bay facility to ship LNG to at least 20 countries worldwide.

Another seven U.S. LNG terminals have applied for permission to become exporters. Cheniere Energy recently received authorization to export natural gas from the Sabine Pass LNG terminal in Cameron Parish, Louisiana. Construction of liquefaction facilities is expected to commence in 2012. A total of four trains are being built, with one train completed every six-to-nine months beginning in the first half of 2015. Cheniere expects to offer bi-directional services at a rate between $1.40/MMBtu to $1.75/MMBtu (million BTU).

One customer eager to receive LNG is Korea Gas Corp. (Kogas), which has agreed to buy about 3.5 mtpa of LNG from train three once it goes online around 2017. “We have sold 16 mtpa of the 18 mtpa being developed at the Sabine Pass LNG terminal,” said Charif Souki, Chairman and CEO of Cheniere Energy Partners. “We look forward to becoming the first LNG exporter in the continental U.S.”

Price is the big motivator. “Gas in the U.S. is less than $2.7 per MMBtu; in Australia it is $13,” said Samir Brikho, CEL of AMEC, a UK engineering and project management consultancy. “For transportation, you can add in $3, so this is a big opportunity to move U.S. gas to Asia.”

Bechtel has been given a $3.9 billion engineering, procurement and construction (EPC) contract for the first two trains at Sabine Pass. It will commission two liquefaction trains using the ConocoPhillips Optimized Cascade “two-train-in-one” approach for added reliability (Sidebar). Extra turbines and compressors are being included so that one set can be closed down while the plant continues operating at a more reduced rate.

LNG Markets and Infrastructure in the U.S. Benefiting from Rise in Unconventionals

Exploitation of unconventional energy such as shale gas, coal-bed methane and oil sands is creating abundant energy development opportunities in the U.S. So much gas available is promoting a rapid increase in many new projects such as pipelines, chemical process plants and ethylene crackers. That’s good news for those manufacturing, repairing and servicing gas turbines, centrifugal compressors and micro turbines.

ConocoPhillips Restarts LNG Exports from Alaska

ConocoPhillips has resumed shipments of liquefied natural gas from its Alaska plant, an aged facility that was previously targeted for closure, a company spokeswoman said June 13.

The company sent a shipment of LNG last month to Japan, spokeswoman Natalie Lowman said.

ConocoPhillips expects to deliver four or five cargoes of Alaska LNG this year, all of them to Japan, Lowman said. However, she said she could not disclose the customer.

The plant, in the Kenai Peninsula community of Nikiski, is the only LNG export facility in the United States. It began operations in 1969, supplying LNG to Tokyo Gas and Tokyo Electric for most of its operating life.

In early 2011, ConocoPhillips and partner Marathon announced plans to close the facility, citing failure to strike a shipping contract with the Tokyo utilities and difficulties in securing natural gas supplies from the mature Cook Inlet basin.

But new demand for Alaska LNG emerged in the aftermath of Japan's massive earthquake and tsunami last year that wrecked the Fukushima nuclear power plant.

ConocoPhillips in September bought Marathon's 30 percent share in the plant and now has full ownership of the facility.

The LNG plant was closed over the winter. The May shipment was the first since last fall.

Plans for the LNG plant beyond 2012 are unclear, Lowman said. "It's too early to speculate on what might happen after 2012, but all potential uses for the plant depend on local needs, the volume of Cook Inlet natural gas production, or the availability of a natural gas via a pipeline from the North Slope to Southcentral Alaska," she said in an email.

U.S. Appeals Court Sides with EPA on Greenhouse Gas

A federal appeals court on June 26 backed the Environmental Protection Agency's first rules limiting carbon-dioxide emissions, a major victory for the Obama administration.

The U.S. Court of Appeals for the District of Columbia Circuit, in an 82-page ruling, unanimously upheld the EPA's central finding that greenhouse gases such as carbon dioxide endanger public health and welfare.

The court also upheld subsequent EPA rules that imposed greenhouse-gas-emissions standards on cars beginning with the 2012 model year. In another major portion of the ruling, the appeals court rejected industry-backed challenges to the agency's initial greenhouse-gas permitting requirements for power plants and other stationary sources of pollution.

The EPA regulations followed a landmark Supreme Court ruling in 2007 that authorized the agency to regulate greenhouse-gas emissions under the Clean Air Act.

The June 26 opinion, issued jointly by three judges who considered the case, said the EPA's findings about the dangers of greenhouse gases were consistent with the Supreme Court ruling and the Clean Air Act.

The court said the EPA marshaled a "substantial" body of evidence to support its findings, and it rejected arguments that there was too much uncertainty about global warming for the agency to take the actions it did.

"The existence of some uncertainty does not, without more, warrant invalidation of an endangerment finding," the court wrote.

Chief Judge David Sentelle, a Reagan appointee, and Judges Judith Rogers and David Tatel, both Clinton appointees, issued the decision.

The ruling is likely to echo in this year's elections, where Republicans including presidential candidate Mitt Romney are charging the Obama administration with stifling job growth through tighter environmental rules.

The decision was a blow to an array of industry groups, including those representing chemical, energy, farming and mining interests, that brought several challenges to the EPA's regulations. The challengers had argued the regulations were burdensome, costly and not grounded in hard data.

Groups on both sides were quick to respond.

"The court upheld the agency's careful determination, based on a mountain of scientific evidence, that carbon dioxide and other heat-trapping pollutants threaten our health and our planet," said David Doniger of the Natural Resources Defense Council.

"We're still reviewing the decision but obviously we're disappointed. It is likely to impose significant costs on the economy and confer few benefits--an outcome consistent for the regulations from this EPA," said National Mining Association spokesman Luke Popovich. The association represents coal-mining companies.

The EPA said in its findings that greenhouse gases likely were responsible for global warming over the last half-century. That finding was the basis for the agency's new auto-emissions standards and industrial permitting rules.

The ruling comes as the EPA works to finalize its first set of national limits on carbon dioxide from new coal-fired power plants. The new standards, first proposed in March, are expected to make the construction of new coal plants increasingly unlikely as power generators opt for natural gas as a generation source.

CANADA

TransCanada to Build $3.8 Bln Pipeline for Shell British Columbia LNG Plant

TransCanada Corp will build a C$4 billion ($3.8 billion) pipeline to serve Royal Dutch Shell Plc's planned liquefied natural gas plant on British Columbia's northern coast, the company said on June 5.

TransCanada, Canada's No. 1 pipeline company, said it would design and build a 700-kilometer (434-mile) line capable of shipping 1.7 billion cubic feet of gas per day from Dawson Creek in northeast British Columbia to Kitimat, where three LNG plants, including Shell's facility, are planned.

Northeastern British Columbia contains some of the world's largest unconventional natural gas reserves. The Montney and Horn River shale gas deposits alone contain trillions of cubic feet of gas.

However the U.S. market is glutted with its own shale gas production, and British Columbia's producers have pinned their hopes on LNG exports to tap lucrative Asian markets.

TransCanada said in a statement that it expected to complete the line by the end of the decade, pending regulatory and corporate approvals.

The line will run near Enbridge Inc's Northern Gateway oil pipeline project, which will also end at Kitimat. Currently in regulatory hearings, Northern Gateway faces strong opposition from environmental groups and many of the aboriginal communities along its planned route.

That opposition has already added more than a year to regulatory hearings, a delay that encouraged the Canadian government to put in new rules capping the length of such sessions.

However TransCanada's pipeline is expected to get an easier ride.

With little risk of sustained environmental damage from a rupture, natural gas pipelines have not faced the same opposition as oil lines. Also, some aboriginal communities, such as the Haisla who live near Kitimat, have a stake in LNG projects.

'I don't think it will get the same sort of resistance (as Northern Gateway faces),' said UBS Securities analyst Chad Friess. 'In addition, it's starting from square one and subject to the accelerated regulatory review that the Canadian government has put out there.'

The line will serve the LNG export facility planned by and partners Korea Gas Corp, Mitsubishi Corp and PetroChina Co Ltd.

The partners are considering a plant that would initially include two units with capacity of 6 million tonnes each annually, or a total of 2 billion cubic feet a day. The plant could be in service by 2020.

Two other proposals have already received LNG export licenses from Canadian regulators. Kitimat LNG is backed by Apache Corp, Encana Corp and EOG Resources Inc , while the BC LNG Export Co-operative is made up of the Haisla First Nation, Houston-based LNG Partners and natural gas producers.

Shell Led $12 Bln British Columbia LNG Terminal Planned

A massive new liquefied natural gas terminal is planned for Kitimat, B.C. The LNG Canada project led by Royal Dutch Shell would be the third and largest B.C. terminal, capable of shipping 1.2 billion cubic feet of gas a day. It carries a price tag of at least $12 billion, according to B.C. Energy Minister Rich Coleman. That would make it the largest capital project ever undertaken in the province.

However, the development of two other LNG plants already granted export permits by the National Energy Board has been slow, especially compared with competing projects in Australia. In May, Apache Canada announced it was pushing back the in-service date for its Kitimat LNG project to 2016, from 2015. Along with partners EnCana Corp. and EOG Resources, Apache has not made a final financial commitment to the project, but one is expected this fall.

The third and smallest project, BC LNG, has likewise yet to break ground. The joint venture between the Haisla First Nation and Houston-based LNG Partners occupies a floating platform off the Haisla reserve. It has a head start since it could start shipping gas right away off the existing Pacific Northern Gas pipeline.

The LNG Canada and Kitimat LNG projects, as well as a fourth plant proposed for the northern B.C. coast by Malaysian state energy company Petronas and Calgary-based Progress Energy, will likely have to wait for new pipelines to be built directly from the shale gas fields of northeastern B.C. Kitimat LNG’s owners are separately developing the Pacific Trails pipeline to their terminal. Spectra Energy is contemplating investing up to $6 billion in new pipelines in B.C. after 2015.

New natural gas pipelines do not face the same kind of opposition as oil pipelines because the product is a gas and, in case of a leak, it escapes into the atmosphere rather than fouling waterways and soil. While there is a risk of gas exploding at the terminal, such accidents are extremely rare. LNG development also has strong political support in B.C.—all three major parties favour it in principle— because, unlike oil from Alberta, it would almost certainly result in higher royalty revenues.

There are still questions around power and whether the LNG plants could comply with B.C.’s carbon tax, however. Chilling the gas to –162°C such that it liquefies for shipment by pressurized tanker takes a lot of energy. “BC Hydro simply doesn’t have the capacity to provide even close to the amount of power required for these projects,” provincial Conservative candidate Rick Peterson argued May 28 in the Vancouver Sun. “The first three LNG proposals alone...would require about half of the electricity that’s currently consumed by the entire province.” They’d either have to generate their own gas-fired power or necessitate the construction of controversial new dams like BC Hydro’s proposed Site C on the Peace River.

These and other issues need to be worked out quickly or Canada’s opportunity will be lost, many in the industry worry. Though the market for LNG in China, South Korea and newly nuclear-free Japan is growing fast—LNG currently fetches six times the price there as the equivalent volume of gas in North America—so is the supply. Australia alone has $175 billion in LNG infrastructure planned for completion over the next five years. “Canada has a finite period of time to capitalize on this opportunity,” says Lance Mortlock, lead author of a recent report on the industry’s opportunities and challenges from advisory firm Ernst & Young.

At the same time, Canada’s American export market, worth $31 billion in 2005, is dwindling to almost nothing as a result of growing shale gas production stateside. China too has huge shale gas reserves that will satisfy much of its domestic demand as extraction techniques pioneered in North America spread there. It’s not an exaggeration to say the fate of Canada’s natural gas sector rests on rapid LNG development. Ernst & Young puts the total investment required in LNG infrastructure at $50 billion over the next five to 10 years.

That still doesn’t mean every project will get built. Andrew Potter, an analyst with CIBC World Markets, expects to see a flurry of mergers and acquisitions as long-term supply contracts firm up between customers in Asia and particular terminals, pipelines and upstream gas producers in Canada. “There is no logic at all to seeing three to five facilities built with three to five independent pipelines,” he said in a conference call.

Methane Emissions Are Half EPA Estimate According to API ANGA Study

API’s Director of Regulatory and Scientific Affairs Howard Feldman told reporters June 5 that a URS study prepared for API and the American Natural Gas Association showed that methane emissions from natural gas production were half what had been previously estimated by EPA. He called the new data the most robust the nation now has on this important subject:

“Our new report provides the best, most comprehensive estimate of methane emissions from U.S. natural gas production. It’s based on data from ten times as many wells as support the estimate EPA has been using.

“This emissions information is critically important because it allows oil and gas companies, citizens, and regulators to gauge the industry’s impact on the environment and allows companies to measure continued efforts to reduce their environmental footprint.

“The API-ANGA emissions estimate, which is half EPA’s estimate, is more accurate because it’s based on emissions from 91,000 wells operated by 20 companies, distributed over a much broader geographic area. EPA’s data were derived from only 8,800 wells.

“The fact that these emissions are much less than earlier, more limited estimates and the fact that operators are already working to reduce emissions from natural gas production is good news for the future of U.S. natural gas development and the game changing benefits of job creation and economic growth that will come with it.”

U.S. / CANADA

U.S. and Canada Competing for Asian Interest in LNG Export Projects

As Alaska and British Columbia compete to attract Asian interest in their LNG export projects, at least one observer believes Alaska may have the upper hand.

Charles Ebinger, senior fellow and director of the Energy Security Initiative at the Brookings Institution, said Alaskan natural gas could, by 2020, be one of the most competitive sources of U.S. LNG exports.

Ebinger co-wrote an LNG exports study for the Brookings Institution. That study highlighted recent developments in Alaska, where major oil producers settled a dispute with the Alaskan government to develop natural gas resources at Prudhoe Bay. Production is expected to travel from Alaska's North Slope to Alaska's southern coast where it will be liquefied and exported at a future large-scale terminal.

If the project scale is large enough, Alaskan exports could be more competitive than LNG exports from British Columbia, according to the study. The Brookings study projected a scenario in which 1 Bcf/d is exported from Alaska and another scenario in which 3.1 Bcf/d is exported from Alaska. The larger-scale terminal could potentially serve Japanese markets in the range of $8/MMBtu.

Sensing the showdown, officials from Alaska and British Columbia continue to hype the benefits of their respective projects.

Sen. Lisa Murkowski, R-Alaska, recently pitched the U.S. ambassadors of Japan and South Korea on the benefits of importing natural gas from Alaska's North Slope. According to a May 22 release, both Ambassador Ichiro Fujisaki of Japan and Ambassador Choi Young-jin of South Korea showed interest in the potential for an Alaska natural gas pipeline and liquefied natural gas project to deliver affordable energy to Asia.

"They recognize the ample opportunities for investment that exist in Alaska," Murkowski said. "Japan and South Korea are almost completely dependent on imports to meet their energy needs, so Alaska's vast natural gas resources represent a very real energy security benefit."

Earlier in May, Murkowski also raised the issue with Japan's Prime Minister Yoshihiko Noda and, separately, with members of Japan's Parliament.

Meanwhile, British Columbia Premier Christy Clark recently returned from a "jobs and trade mission" to Japan, Korea and the Philippines.

"Our government has been focused on promoting British Columbia's natural advantages to Asian investors," she said in a statement. "This trade mission was about building on our strategic trade relationships so we can continue building our economy's momentum."

During the trip, Clark met with KOGAS and Mitsubishi Corp, who have partnered with Shell Canada Ltd. and PetroChina Co. Ltd. to jointly develop an LNG facility near Kitimat, which is expected to handle 12 million tonnes of LNG a year.

The province and Japan Oil Gas and Metals National Corp. also signed an agreement to co-operate and share information on natural gas activities in British Columbia according to the release.

ASIA

Rising Asian Gas Demand Helps LNG Tankers Dodge Price Slump in New Ship Prices

Liquefied natural gas tankers, the most expensive type of vessel, have avoided a slump in new ship prices because of rising Asian gas demand and limited competition from Chinese shipbuilders.

Prices for tankers able to hold 160,000 cubic meters of gas have held steady at about US$202 million since 2010, based on Clarkson Plc data, bolstering earnings for South Korea-based Samsung Heavy Industries Co. and Daewoo Shipbuilding & Marine Engineering Co., the biggest makers of the vessels. Capesize dry-bulk ship prices have plunged 18 percent in the period because of a glut partly caused by China financing orders to prop up local yards.

Chinese shipbuilders have been largely shut out of the LNG tanker market as the vessels are more complicated and more expensive to build than ships for carrying commodities or containers. Thats curtailing competition for the 140 new LNG tankers that ship-classification society ABS expects operators to order over the next five years.

“Our preference is to go to Korea unless theres a specific reason not to”, said Sverre Prytz, managing director at BW Ventures, which operates 14 LNG ships through unit BW Gas. Some people are trying to build in China, but they do it with hesitation.

South Korean yards have won all 13 of the new LNG tankers ordered this year through April, according to shipbroker Clarkson. The country also built 197 of the 372 tankers afloat. Japanese yards, which last won an order in 2011, are the second- biggest builder with 103 in service.

China Yard Samsung Heavy advanced as much as 6.8 percent, the biggest gain since Oct. 24, to 36,950 won and traded at 36,550 won as of 10:24 a.m. in Seoul. The stock is the fourth-best performer on the MSCI Asia Pacific Index today. Daewoo Shipbuilding climbed as much as 6 percent to 27,600 won.

Only one Chinese shipbuilder, Hudong-Zhonghua Shipbuilding (Group) Co., has built LNG tankers. The yard, a unit of state-owned China State Shipbuilding Corp., has built five vessels for Chinese companies and is working through orders for five more. The Shanghai-based shipbuilder didnt reply to faxed questions.

Samsung Heavy has built 11 ships that can each move 266,000 cubic meters of LNG for an Exxon Mobil Corp. venture in Qatar. The company, Daewoo Shipbuilding and Hyundai Heavy Industries Co. also shared orders for 44 vessels from Qatar in 2007. The three shipbuilders have a combined backlog of 55.

China is encouraging domestic ship operators to order LNG tankers locally to help the biggest yards expand. The country’s LNG imports will probably generate orders for 60 tankers over five years, according to Houston, Texas-based ABS.

China Shipping Development Co. will prefer to use domestic shipbuilders as it seeks new tankers, said Ding Zhaojun, the head of its finance department. The China Shipping Group Co. unit has ordered four LNG carriers from Hudong-Zhonghua through a venture with Mitsui O.S.K. Lines Ltd. It aims to have a fleet of 10 by 2016, Ding said. China LNG Shipping Holdings Ltd., operator of the first China-built LNG tanker, has also issued a tender for two vessels to local yards. Three companies bid, including Hudong-Zhonghua, said Yan Weiping, China LNGs general manager.

“As a Chinese operator, we favor Chinese yards”, he said. The other bidders were a unit of Shanghai-listed China Shipbuilding Industry Co., and Nantong COSCO KHI Ship Engineering Co., which is a venture between China Ocean Shipping (Group) Co. and Hyogo, Japan-based Kawasaki Heavy Industries Ltd.

China LNG deployed as many as 30 people at a time to watch over construction of the Dapeng Sun, the first vessel built by Hudong-Zhonghua. “Five is usually enough for dry-bulk ship orders”, said Yan, who also made frequent site visits.

“I was even more anxious than people in the yard”, he said. The Dapeng Sun was completed in 2007, according to data compiled by Bloomberg. China LNG, a venture between Cosco Group and China Merchants Group, now sends fewer people to the shipbuilder because of rising experience, Yan said.

China may increase natural-gas consumption fourfold by 2030 to 600 billion cubic meters, according to Wood Mackenzie, an Edinburgh, Scotland-based consulting firm, because of economic growth and a move to pare its reliance on coal. The country is operating five LNG terminals and building six more that will open through 2014, China National Petroleum Corp. said in its annual oil and gas research report published in February.

China Petrochemical Corp. and PetroChina Co. are both buying gas from Australian projects, including Chevron Corp.-led Gorgon and Royal Dutch Shell Plc-led Sunrise.

Japan, the world’s biggest buyer of LNG, boosted imports 12 percent in the first four months as it pares its use of atomic power following last years tsunami. The country may need as much as 90 million metric tons of LNG a year by 2025, Shigeru Muraki, the chief executive of Tokyo Gas Co.‘s energy solution division, said. It imported 78.5 million last year, according to preliminary Ministry of Finance figures released in January.

Prices for LNG tankers have also been supported by Asian energy companies preference for chartering vessels on long-term contracts, often about 20 years. This security provides a further incentive for the ship operators to buy vessels from experienced yards where possible, said Ralph Leszczynski, the Beijing-based head of research at shipbroker Banchero Costa & Co.

Shipowners would prefer to spend a little bit more to have a safe and reliable ship than save and have problems, he said. Moving from building simple bulk carriers to building LNG ships is a big step up.

The high cost of LNG tankers and use of long-term deals have also helped prevent a capacity glut that has caused a slump in the prices in other vessels. Prices for very large crude carriers and ships able to carry 13,000 containers have fallen about 8 percent since April 2010, according to Clarkson.

Worldwide 71 LNG tankers are on order, with a total capacity of 11.1 million cubic meters, as of May 1, according to Clarkson. That’s equivalent to 21 percent of the capacity of the current fleet. The ratio for on-order container ships is 24 percent and 29 percent for dry-bulk and 16 percent for oil tankers.

“The shortage of new LNG tankers has pared the spot market to as few as three vessels over the past 18 months, underlining the demand for new ones”, said Tony Regan, a consultant with Singapore-based Tri-Zen International Ltd. and former Shell LNG executive.

“I think were going see to an extremely tight market for at least the next couple of years”, he said. “There’s a tremendous growth in demand, and as routes get longer were going to require more vessels.”

AUSTRALIA

Korea’s SK Group to Invest up to $520 Mln in Australia Gas

South Korea's growing demand for natural gas has driven giant conglomerate SK Group to its biggest investment in Australia, as it agreed to pay up to $520 million for a stake in two fields off the north coast held by ConocoPhillips and Santos.

The deal will lead to SK's power and gas unit paying for three wells to be drilled at the Caldita-Barossa deposits, about 300 kilometers north-west of Darwin, with a view to proving up enough gas for conversion into LNG.

Should enough be found, it may underpin a long-awaited expansion of Conoco's Darwin LNG project or support a floating venture, said Santos vice-president WA and Northern Territory, John Anderson.

Rising electricity use is expected to lift LNG demand in South Korea, the world's second-biggest importer of the fuel, by 40 percent by 2024. Korean LNG contracts are helping underwrite Santos' $16 billion GLNG project, Chevron's Gorgon venture and gas from Shell's floating Prelude plant.

SK's E&S subsidiary, which currently imports LNG only from BP's Tangguh plant in Indonesia, is increasing purchases of LNG to supply planned new power plants that will head off an electricity shortage, a spokesman in Seoul said June 7.

He said SK was attracted to the Caldita-Barossa venture because of relatively low transportation costs from the Timor Sea to Korea, the technical viability of the resource, and the reliability of the partners in Conoco and Santos.

"Those three factors meant those fields met our criteria," he said.

SK will initially pay $260 million in drilling expenses to acquire a 37.5 percent interest in the Caldita-Barossa fields. It will then have the option of raising its stake to 49.5 percent with a further $60 million payment to Conoco and Santos.

SK will also fund up to $90 million in initial engineering and design work for the project, with the work to get under way in 2014, subject to the results of the drilling.

Should an LNG project go ahead, the Korean group will pay a further amount of up to $110 million as various milestones are met, including a final investment decision and first delivery of LNG cargoes.

Conoco's stake in the venture will initially fall to 37.5 percent from 60 percent, while Santos's drops to 25 percent from 40 percent.

Should SK exercise the option to raise its interest, it will become the biggest partner, with the U.S. company's holding falling to about 30 percent and Santos' to about 20 percent.

Santos chief executive David Knox signaled last month a deal was getting close on Caldita-Barossa after long expressing frustration about a lack of progress towards development of the resource. The company has been on a mission to monetize its undeveloped gas fields off the north coast, and the deal with SK is the third of a string of transactions that have realized a higher value for the assets than most analysts were giving credit for.

Santos sold its Evans Shoal asset last year to Italy's Eni for up to $350 million, and previously divested part of its interest in the Petrel and Tern deposits to France's GDF Suez for a floating LNG project.

The deal with SK "is positive for Santos because it's a stranded gas asset that we probably don't value as highly as the transaction implies," said UBS energy analyst Gordon Ramsay. "This moves it a further step forward to potential commerciality."

The Caldita-Barossa deposits in the Timor Sea are regarded as a [potential candidate to feed an expansion of ConocoPhillips' Darwin LNG project. That plant currently consists of a single train producing about 3.5 million tonnes per year of LNG but the site has full environmental approval for up to 10 million tonnes a year of production.

Conoco's president of its Australian business, Todd Creeger, said yesterday that Darwin was one option for commercialization, alongside a floating project.

The determining factor on how the fields will be developed will be the appraisal drilling program, which should get under way in early 2013, Santos' Mr Anderson said.

"Clearly the more gas we can show is recoverable it will start to swing it towards Darwin," he said.

The fields are thought to hold quite a lot of the contaminant CO2, however, which would need to be removed.

The Korean funding should completely cover the drilling costs, effectively giving ConocoPhillips and Santos a free option over the three wells in exchange for diluting their interest in the resource.

NT Chief Minister Paul Henderson said the deal meant a potential new gas project for the territory.

Browse JV Pipeline Bill Creates Cost Pressure for Woodside LNG Project

Already struggling to contain costs on the Browse LNG project, Woodside and its joint venture partners face a multi-billion bill for a 650km domestic gas pipeline.

Premier Colin Barnett said that while negotiations over the project had yet to be concluded it would be expected as for other WA ventures to supply up to 15 percent of its gas to WA industry.

To maximize the value of this gas, he said that a land-backed pipeline from James Price Point to Port Hedland to join the State's pipeline network would ultimately be necessary, rather than allowing the partners to provide offsetting gas from other developments as allowed under State Agreements.

I do not rule anything in or out, but to get the value of what is a significant amount of domestic gas would require a pipeline to be built at some stage, he said.

Obviously, if domestic gas is there, it will not be hard to find someone (other than government) to build a pipeline to run the gas down to Port Hedland, he told a post-Budget Estimates hearing.

While Woodside and its partners may be able to find customers or infrastructure groups to underpin the cost of the pipeline, estimated to be in the billions, they may be forced to stump up the funds themselves.

Woodside, which operates the venture on behalf of partners BHP Billiton, Shell, Chevron, BP, Mitsui and Mitsubishi, would not be drawn on the issue, saying on June 5 only that it was continuing discussions with government around domestic gas.

Analysts think the massive greenfields venture will cost somewhere between $30 billion and an eye-watering $50 billion, potentially threatening the viability of the development.

BHP and Chevron are said to favor piping gas to the existing North West Shelf plant at Karratha to help offset declining reserves in that project's fields and to shave as much as $15 billion from the cost of processing Browse gas at James Price Point.

Having to build a land-based pipeline for domestic gas may give BHP and Chevron greater sway in their arguments to build a costlier but one-off sea-based pipeline to Karratha and existing LNG facilities and its domestic gas plant.

Opposition spokesman Bill Johnston said the Premier needed give the partners certainty.

One of the biggest dangers to developments in this State is the Premier changing his mind, Mr Johnston said.

There is capacity in the domestic reservation policy to swap gas, to allow a project to come on stream without having to build unnecessary infrastructure.

It may be that the volumes from Browse justify a domestic gas pipeline, but like the troubled Albany pipeline project the Premier can't wish it into existence.

The Browse partners have delayed a final investment decision on their project until the middle of next year.

European Turmoil Drives Qatar to Switch LNG Exports to Asia Causing Concern in Australia

Turmoil in Europe has driven the world's biggest LNG producer Qatar to switch its exports to Asia, posing a threat to Australian projects, according to Woodside Petroleum boss Peter Coleman.

As he battles to keep the $40 billion Browse project on track, Mr Coleman used a business function in Perth June 3 to warn of the risks posed to the wave of LNG projects in development around the nation, including from the Federal Government's carbon tax.

He was joined by Wesfarmers managing director Richard Goyder and Fortescue Metals Group chief executive Nev Power, who said there were likely to be severe unintended consequences to the local economy from the tax, which started on July 1.

However, it was the financial headwinds in Europe which Mr Coleman said were causing him sleepless nights, given slow growth on the continent had altered the LNG landscape.

So supply that was meant to go to Europe . . . has been redirected into Asian markets, so we are competing head to head in Asian markets now with the largest of the suppliers in the world in the Qataris, he said. And that wasn't in the plans before.

Woodside said its long-term outlook for the LNG market remained positive and should grow by an average annual rate of 4 per cent between now and 2025.

The Woodside chief said he was already being approached by suppliers trying to pass on costs of the carbon tax, which would hit profits an Australia's competiveness.

I have fixed contracts that are set at global market rates, he said. All you are doing to me is getting into (our) margin, I can't pass on those costs.

Trade-exposed industries will be given transitional assistance under the tax.

Mr Goyder said while he believed action was needed on global warming, setting a price of $23 a tonne on carbon when international prices were less than half that was nonsense.

Coles would be vigilant in ensuring suppliers did not pass on unjustified costs from the carbon tax and was taking steps to reduce its emissions, he said.

Mr Power said the tax would clog development and defer investment.

The three men were upbeat on China's economic outlook, but said Canberra should provide more policy certainty and consultation.

Technip Awarded Contract for Ichthys FPSO Unit

Technip has been awarded a services contract for the Ichthys floating production storage and offloading (FPSO) unit. The FPSO unit will be located in the Browse Basin, Western Australia, at a water depth of 250 meters. Technip will provide these services to Daewoo Shipbuilding & Marine Engineering (DSME).

This contract covers detailed engineering and procurement assistance for the topsides(1) facilities of the 1.2 million barrels storage capacity Ichthys FPSO.

The Ichthys LNG project is a joint venture between INPEX (operator) and Total. Gas from the Ichthys Field, in the Browse Basin approximately 200 kilometers offshore Western Australia, will undergo preliminary processing offshore to remove water and extract condensate. The condensate will be pumped to the FPSO facility anchored nearby, from which it will be transferred to tankers for delivery to markets. The gas will then be exported to onshore processing facilities in Darwin via an 889 kilometers subsea pipeline. The Ichthys LNG project is expected to produce 8.4 million tonnes of LNG and 1.6 million tonnes of LPG per annum, along with approximately 100,000 barrels of condensate per day at peak.

Technip's operating center in Kuala Lumpur, Malaysia, will execute the project.

KBR Selected by Hoegh for Pre-FEED FLNG Studies of Israel, Australia Projects

KBR announced June 25 that it was selected as Hoegh's preferred engineer to execute pre-FEED studies for two of its projects off the coast of Israel and offshore Australia.

KBR will provide the pre-FEED study for the King liquefied natural gas-floating production storage and offloading (LNG-FPSO) facility currently being evaluated for Noble Energy's giant Tamar gas field off the coast of Israel. KBR has developed FPSOs that are in use worldwide and is recognized as one of the world's leading providers of onshore LNG plants and FPSOs.

Hoegh LNG awarded KBR a second FLNG pre-FEED study for an unnamed project offshore Australia. The four-month pre-FEED is intended to provide a Total Installed Cost (TIC) estimate for a two mtpa FLNG facility to enable further evaluation of the project. KBR will perform a cost estimate study, taking Hoegh's existing generic LNG FPSO FEED study and adapting the capex cost for the operator's field-specific basis of design. Should the project economics prove viable, FEED could start as early as 4Q 2012.

Both projects will be performed in KBR's London Operating Center, utilizing the company's substantial and growing FLNG engineering capability spread over the London, Houston and Perth offices.

"We are excited about providing the initial engineering work for an innovative LNG FPSO solution to support Hoegh LNG's already-developed concept," said Roy Oelking, KBR Group President, Hydrocarbons. "We are pleased to work with Hoegh LNG, Daewoo Shipbuilding & Marine Engineering Co., and the Tamar field owners in developing one of the first LNG FPSOs to come to market. KBR has been working with Hoegh LNG since 2010 and we are confident that, together, we will help Hoegh deliver the optimum solution for bringing Tamar gas to the market."

Rising Asian Gas Demand Helps LNG Tankers Dodge Price Slump in New Ship Prices

Liquefied natural gas tankers, the most expensive type of vessel, have avoided a slump in new ship prices because of rising Asian gas demand and limited competition from Chinese shipbuilders.

Prices for tankers able to hold 160,000 cubic meters of gas have held steady at about US$202 million since 2010, based on Clarkson Plc data, bolstering earnings for South Korea-based Samsung Heavy Industries Co. and Daewoo Shipbuilding & Marine Engineering Co., the biggest makers of the vessels. Cape size dry-bulk ship prices have plunged 18 percent in the period because of a glut partly caused by China financing orders to prop up local yards.

Chinese shipbuilders have been largely shut out of the LNG tanker market as the vessels are more complicated and more expensive to build than ships for carrying commodities or containers. That’s curtailing competition for the 140 new LNG tankers that ship-classification society ABS expects operators to order over the next five years.

“Our preference is to go to Korea unless there’s a specific reason not to”, said Sverre Prytz, managing director at BW Ventures, which operates 14 LNG ships through unit BW Gas. Some people are trying to build in China, but they do it with hesitation.

China Petrochemical Corp. and PetroChina Co. are both buying gas from Australian projects, including Chevron Corp.-led Gorgon and Royal Dutch Shell Plc-led Sunrise.

Japan, the world’s biggest buyer of LNG, boosted imports 12 percent in the first four months; as it pares its use of atomic power following last year’s tsunami. The country may need as much as 90 million metric tons of LNG a year by 2025, Shigeru Muraki, the chief executive of Tokyo Gas Co.‘s energy solution division, said. It imported 78.5 million last year, according to preliminary Ministry of Finance figures released in January.

Prices for LNG tankers have also been supported by Asian energy companies’ preference for chartering vessels on long-term contracts, often about 20 years. This security provides a further incentive for the ship operators to buy vessels from experienced yards where possible, said Ralph Leszczynski, the Beijing-based head of research at shipbroker Banchero Costa & Co.

Ship owners would prefer to spend a little bit more to have a safe and reliable ship than save and have problems, he said. Moving from building simple bulk carriers to building LNG ships is a big step up.

“I think we’re going see to an extremely tight market for at least the next couple of years”, he said. “There’s a tremendous growth in demand, and as routes get longer were going to require more vessels.”

Cost of Santos LNG Project Is Hiked up to $18.5 Bln

Santos hiked the cost of its Gladstone LNG project on June 28 by over 15 percent to $18.5 billion, saying it needs to drill 300 more wells to find gas for a planned 2015 start-up, underlining hurdles facing Australia's coal seam gas industry.

Shares in Santos, the second of three coal seam gas-to-liquefied natural gas (CSG to LNG) projects to announce a big cost hike, fell 5 percent as the news raised concerns it may scramble to find gas that has already been pre-sold to customers.

Energy firms kicked off $50 billion of CSG to LNG projects in Australia less than two years ago, but industry experts have flagged that plans are running off track due to disappointing drilling results, which have led to rising costs.

"My take is that they are short of gas and the rumors have been flying thick and fast for a year that these plants are going to be short of gas," said Peter Strachan, an analyst with Stock Analysis in Perth.

Coal seam gas operators are aiming to drill tens of thousands of wells targeting methane held in coal beds, which is then converted to LNG.

Santos had so far drilled 450 wells out of a planned 1,000 before it ships its first LNG cargo, but given permitting delays and a rate of 150 wells a year its plan seemed optimistic, said Neil Beveridge, an analyst with Bernstein Research in Hong Kong.

"The greatest risk for Gladstone LNG is failure to meet gas targets which will result in purchase of shortfall LNG to meet contractual requirements," Beveridge said in a note.

"We expect Santos will announce further capex increases and will be forced to purchase additional third party gas to avoid severe penalties on failure to meet LNG targets."

Like most LNG developments, much of Gladstone LNG's gas is already sold into long-term oil-linked contracts which the project is now under pressure to deliver.

Santos said the extra $2.5 billion for Gladstone had been slated for after 2015, but was being brought forward in order to drill the 300 extra wells before the end of 2015.

It expected to ramp up drilling to more than 200 wells a year from next year.

"It's important to stress that this additional capex is not a result of a significant cost overrun or any major scope changes in the project. Our life of project cost assumptions are consistent with what we had at our final investment decision," Santos Chief Executive David Knox told reporters by phone.

Knox said about 10 percent of the cost increase was due to a combination of cost and scope changes in the project, with 90 percent of the cost increase a result of pushing parts of the project development forward.

The company has not published figures on capital expenditures for the life of the project and Knox said future capex would likely depend on gas field productivity.

"There will be expenditure beyond 2015 ... there is a degree of uncertainty around that and really ultimately it's going to depend on the performance of our underpinning fields, Fairview and Roma," Knox said.

Productivity at the Fairview gas field was improving, Knox said, but output at the Roma field would not be known until it started production in about 18 months.

Moving some of the planned drilling forward could provide the company with opportunities to produce and sell more cargoes to its customers during the plant's ramp-up period, he said.

Malaysia's state-run oil company Petronas and South Korea's Korea Gas Corp, who are also equity partners in the project, have both committed to 20 year LNG supply contracts and will buy a total of 7 million tonnes of the 7.8 million tonnes the plant will produce per year.

Santos's cost blowout follows an announcement earlier this year by BG Group that its rival Queensland Curtis Island LNG project would face a 36 percent cost increase to $20.4 billion, citing regulatory costs, some changes to the project, and a stronger Australian dollar.

Analysts expect a third project, Origin Energy's Australia Pacific LNG (APLNG) to face cost increases to its development as well.

Australian producers are also under pressure from abundant U.S. shale gas which could soon provide cheap competition.

Santos said it would be able to fund its $750 million share of the extra spending and had no need or plan to raise additional debt or equity for Gladstone LNG or any other of its approved projects.

It reaffirmed it expects to spend A$3.75 billion ($3.78 billion) in capital in 2012.

The Gladstone LNG project is 30 percent owned by Santos. Malaysia's Petronas and France's Total each own 27.5 percent and Korea Gas Corp owns 15 percent.

Alfa Laval Wins Order to Supply Equipment for World's First FLNG Facility

Alfa Laval has won an order from a Technip Samsung Consortium (TSC) to supply Alfa Laval equipment to Shell’s Prelude FLNG facility. Alfa Laval is unable to disclose the exact value of the order due to a confidentiality agreement.

FLNG opens up new business opportunities for countries looking to develop their gas resources, bringing more natural gas to the market and Shell is the first to go ahead with an FLNG project, Prelude FLNG.

The Alfa Laval equipment consists of desalination units, heat exchangers and filters. The desalination units will convert sea water into fresh water to be used for steam generation, process water and potable water. The heat exchangers will use seawater in the vital cooling applications in the gas liquefaction process.

“We are very proud to be part of this technology breakthrough in the energy field”, says Lars Renström, President and CEO of the Alfa Laval Group. “This order confirms our strong position as a reliable partner to the major players in the oil and gas industry.”

The Prelude facility being built by the TSC at the Samsung Heavy Industries shipyard in Geoje, Korea will measure 488 meters from bow to stern and weighing around 600,000 tones when fully loaded. It will be moored over 200 kilometers from land in Western Australia and will produce gas from offshore subsea fields, treat and liquefy it onboard via a cooling process before storing and exporting the LNG via conventional LNG carriers.

Alfa Laval is listed on the Nordic Exchange, Nordic Large Cap, and, in 2011, posted annual sales of about SEK 28.6 billion (approx. 3.2 billion Euros). The company has 16 000 employees.

Technip Awarded Subsea Contract for Shell’s Prelude FLNG Project

Technip has been awarded a large subsea installation contract by Shell Development (Australia) Pty Ltd for the Prelude Floating Liquefied Natural Gas (FLNG) facility moored some 200 kilometers off the northwest coast of Australia, in the Browse Basin, at a water depth of approximately 240 meters.

Technip’s operating centers in Perth, Australia, and Kuala Lumpur, Malaysia, will execute the contract, with engineering to commence immediately. Technip’s spoolbase in Orkanger, Norway, will be welding the flowline linepipe provided by Shell Development (Australia) Pty Ltd. Vessels from the Group’s fleet will be used for the offshore campaigns, including the Deep Energy and the Deep Orient.

INDIA

LNG Project Could Spark $1 Bln in India’s Gas Sector Investment

Royal Dutch Shell, Reliance Power and Kakinada Ports will jointly build a floating terminal off the eastern coast of Andhra Pradesh to receive imported liquefied natural gas and convert it into gas for supply, a project that could entail investments of $1 billion in the state's gas sector.

The project will start with a capacity of up to 5 million tonnes per annum (mtpa), which can be scaled up to more than 10 mtpa. It will be completed in 2014.

India has only two LNG terminals in India, both of them located on the west coast. There is no LNG terminal in south India though there is a huge unmet demand for gas in the region.

Gas majors like Petronet LNG, ONGC and GAIL have announced plans to set up similar LNG terminals in Andhra Pradesh, which has emerged as an attractive destination for LNG.

If LNG is regasified in a floating storage and regasification unit (FSRU) on Andhra Pradesh's east coast, gas will cost $15.68 per mmBtu. On the other hand, if gas is transported from the west coast, the delivered price should be $18.65 per mmBtu thanks to higher gas transport costs and additional taxes, said a recent feasibility study by Andhra Pradesh Gas Distribution Corporation.

Southern India lacks coal resources, depending on gas to fuel power plants. Due to falling gas production at Reliance Industries' KG D6 block, several plants in the south are running at low capacity, worsening the power shortfall.

As per data available with the Central Electricity Authority, the southern region faced electricity shortfall of 15.5% during April, the highest among all regions of the country.

While the FSRU is estimated to cost $500 million, developers must spend an equal amount to develop onshore facilities including gas pipelines.

R-Power said the project is expected to be completed by 2014 and the initial capacity can be doubled to over 10 mtpa in future. Gas imports through the terminal will also fire R-Power's 2,400 megawatt Samalkot gas-based power plant in Andhra Pradesh. Shell and R-Power will hold majority stake in the terminal company.

"The LNG receiving terminal in AP is of strategic importance to Andhra Pradesh and India," said JP Chalasani, CEO, R-Power. "We believe Shell, with its large LNG portfolio and experience in operating LNG terminals, will add immense value to the project."

The supply of natural gas in India would increase from 179 mmcmd in fiscal year 2011-12 to 279 mmcmd by 2017-18, Kotak Institutional Equities, a domestic broker, said in a report on May 17.

Reliance Power, Shell to Set Up LNG Terminal on India's East Coast

Reliance Power Ltd. said May 31 that it has entered into an agreement with Royal Dutch Shell PLC to set up a 5-million-metric-ton liquefied natural gas terminal on the east coast.

The two companies together hold a majority stake in a consortium to set up the terminal for importing LNG, with the minority stake being held by unlisted Kakinada Seaports Ltd.

The terminal is expected to start operations by 2014 and its capacity may be doubled to 10 million tons later, Reliance Power said.

MALAYSIA

Malaysia Completes First LNG Re-Gasification Terminal

On June 8, Prime Minister Dato' Sri Mohd Najib Tun Razak and Melaka Chief Minister Datuk Seri Mohd Ali Rustam officially launched Malaysia’s first LNG regas facility in conjunction with the World Gas Conference 2012 taking place in Kuala Lumpur.

PGB is currently progressing ahead with the preparation to commission the project for commercial operation scheduled for August.

PETRONAS' plan for the development of the project, also referred to as Re-gasification Terminal (RGT) Sungai Udang, was officially announced by the Prime Minister on June 10 , 2010 when he presented the 10th Malaysia Plan in Parliament. The project was then estimated to cost RM3 billion.

Following the announcement, the task of developing the RGT was assigned by PETRONAS to PGB, which implemented the project on a fast-track basis to meet its completion deadline in record time and with a significantly lower cost than its original RM3 billion budget.

Situated three kilometers offshore Sungai Udang, Melaka, the RGT is considered an engineering feat by the industry. Developed and based on a revolutionary design, it comprises the world's first-of-its-kind re-gasification unit on an island jetty (JRU), two floating storage units (FSU) and a three-km sub-sea pipeline connecting to a new 30-km onshore pipeline that links to PGB's existing Peninsular Gas Utilization (PGU) pipeline network.

The FSU concept has enabled the project team to save invaluable two years, compared to building land-based re-gasification and storage facilities. The two FSUs, formerly Tenaga-class LNG tankers owned by PETRONAS' shipping arm MISC Bhd, will be permanently berthed at the JRU.

The conversions of the tankers into FSUs were carried out at Malaysia Marine and Heavy Engineering Holdings Bhd's shipyard in Pasir Gudang, Johor and Keppel Shipyard, Singapore. The FSUs have been designed to be berthed for at least 20 years without the need for dry docking.

The JRU, which is the core of the RGT, is designed to receive LNG, re-gasify it and deliver natural gas via the sub-sea pipeline to the PGU pipeline. The JRU has a capacity to receive, store and vaporize up to 3.8 million tonnes per annum (530 million standard cubic feet per day) of LNG, which will be imported from various supply sources globally.

The project was developed in anticipation of future increase in gas demand in the face of depleting indigenous gas reserves, as part of PETRONAS' efforts to ensure sufficient and secure natural gas supply for Malaysia.

Its implementation has also enhanced the capability of the local players involved in the project, exposing them to new technologies and expertise that would be beneficial to their growth and the development of Malaysia's oil and gas industry.

Petronas Gets Approval to Invest In Floating LNG Project

Malaysian oil and gas company Petroliam Nasional Bhd., or Petronas, is pushing ahead with its floating liquefied natural gas facility project and will compete with Royal Dutch Shell PLC's (RDSA) proposed floating LNG plant to be the world's first of its kind.

State-run Petronas has made a final investment decision to go ahead with development of a floating LNG facility in Sarawak state on the island of Borneo which it hopes to commission in 2015, the company's chief executive, Shamsul Azhar Abbas, said June 4 at the World Gas Conference.

Global demand for gas is on the rise, as it's a cheaper and cleaner alternative to liquid fuels. As conventional fuel reserves are depleting, advanced technology is making it possible to access previously unfeasible resources like shale gas and offshore gas.

Petronas' floating LNG facility project will provide "a strategic solution to monetize marginal and stranded gas fields," the company said in a recent investor review.

Shell is building its floating LNG plant to develop the Prelude gas fields 200 kilometers off Western Australia's Kimberly Coast, which are inaccessible through conventional means.

The Prelude LNG floating terminal is expected to cost around $3 billion-$3.5 billion per one million metric tons of production capacity, equating to $10.8 billion-$12.6 billion, a company executive said earlier.

Six times heavier than the world's biggest aircraft carrier and 488 meters long, Prelude will float in waters off Australia's northwestern coast. It will be capable of producing 3.6 million tons a year of LNG and additional volumes of condensate and liquefied petroleum gas.

The cost of Petronas' proposed floating LNG project in Malaysia isn't known.

Petronas also announced that it had completed construction of the country's first LNG regasification terminal in Melaka, which will start commercial operations in August.

GE Oil and Gas Secures $150 Mln Deal to Supply LNG Technology to Petronas

GE Oil and Gas, a unit of General Electric Co, has secured a $150 million (RM477 million) deal to supply liquefied natural gas technology to Petroliam Nasional Bhd (Petronas).

The Petronas LNG Train 9 project will add 3.6 million tonnes per annum (mtpa) to the existing 25.7 mtpa production capacity at the Petronas LNG Complex in Bintulu, Sarawak.

Malaysia is the world's second largest exporter of LNG.

GE vice-president Prady Iyyanki said the company would supply proven, advanced turbo-compression technology to the Bintulu complex.

"Train 9 of the Petronas LNG complex will utilize the APCI Split MR liquefaction process technology," he said at a breakfast talk hosted by the company, held on the sidelines of the World Gas Conference.

As part of the contract, he said GE was providing a fully integrated solution for Train 9, including GE Oil and Gas turbo-compression equipment and variable speed drive systems from GE's Power Conversion business.

He said the scope of GE's supply included a low- and medium-pressure mixed refrigerant package and a propane and high pressure mixed refrigerant package, each driven by a frame 7EA gas turbine, with 13MW induction motor running at 3,600 rpm and VSI technology variable speed drive systems.

"The compression trains are vital elements of the liquefaction process, which cools natural gas to liquid state. The GE technology we are providing for the Train 9 project is well-proven and is used across a wide range of LNG projects, including such landmark projects in Asia Pacific region as Gorgon and Ichthys," he said.

Asked how soon the Train 9 project would be completed, Prady said the project could take almost 18 months, but stressed that the project was on schedule.

"It depends on Petronas (on when it wants to start operate the Train 9)."

Elaborating, he said the Train 9 project built on the strong collaboration existing between Petronas and GE, and was part of global frame agreement that had existed since 2009.

"The addition of Train 9 to the Bintulu complex will increase the flexibility of Petronas' LNG portfolio, while also supporting the overall growth of the region's natural gas industry," he said.

Petronas group corporate affairs division senior general manager Datuk Mohammed Medan Abdullah concurred with Prady, saying that it was important for Petronas to have a long-term relationship with its partners to ensure the success of any projects as well as sustain supply.

"We have to bear in mind that this is a long-term business and in such a business, we need to have long-term relationships with our partners.

The Petronas LNG complex in Bintulu is the world's largest integrated LNG production facilities at a single location, consisting three subsidiaries, namely Malaysia LNG Sdn Bhd, MLNG Dua Sdn Bhd and MLNG Tiga Sdn Bhd.

EUROPE / AFRICA / MIDDLE EAST

CYPRUS

Cyprus Makes a Decision to Build LNG Terminal

In a statement ending months of speculation on Cyprus' gas plans, Commerce Minister Neoclis Sylikiotis revealed June 7 that a decision has been made to build a liquefaction plant for natural gas.

"The decision for the creation of a liquefaction terminal has been made. What remains now is to press ahead with the planning for the next steps," Sylikiotis said in his address to the Cyprus Natural Gas Conference held in Nicosia.

The two-day conference - which concluded June 8 was sponsored by Ernst & Young Cyprus, bringing together people from industry, academia and politics. The June 7 proceedings focused on global developments and the impact on the gas market.

Sylikiotis went on to say there is a great deal of interest from companies abroad in an LNG project here, including financial institutions. Last month Sylikiotis told the Mail he met with representatives of Deutsche Bank and Credit Agricole who expressed "a preliminary interest" in investing in a liquefaction terminal on the island.

He said also that the establishment of a state hydrocarbons corporation is a matter of weeks. Meanwhile the government has commissioned the Massachusetts Institute of Technology (MIT) to carry out a study on financial prospects from gas exploitation.

The minister revealed also that soon the government would appoint a team that would enter into negotiations with Noble Energy, which has a gas concession in Cyprus' Block 12. Up until now a government-appointed team was engaged in preliminary talks with the US company on the best way to commercialize the find at the 'Aphrodite' field.

The negotiating team's mandate, Sylikiotis said, would be to reach a "number of agreements which we must sign with the company." He did not elaborate.

During Q&A, the minister was asked to clarify the role of the state hydrocarbons corporation. He said that it would initially be 100 per cent owned by the state, although later on a small stake could be given to the private sector. Although a state company, it would be governed by private law, and would have authority handle all business relating to natural gas - including negotiations with companies, commercial deals etc.

From the audience, Ilan Diamond, a business executive involved in the Pelagic natural gas fields off the coast of Israel, informed the panel that exploratory drilling was expected before the end of the year in the part of the 'Aphrodite' field that lies in Israeli waters.

Cyprus and Israel are currently engaged in negotiations for a unitization agreement regarding the gas-sharing and exploitation of reserves that fall on the maritime boundary between the two nations. Noble has said it plans to carry out follow-up appraisal drilling in the Cypriot field in Q4 or early next year.

In response to a question, Sylikiotis said the unitization agreement is being handled by the Foreign Ministry.

SWEDEN

Swedegas, Vopak Sign Preliminary Agreement for Gothenburg LNG Terminal

The Swedish gas transmission company Swedegas, and Netherlands-headquartered terminal developer Vopak signed a preliminary agreement on June 20 to explore constructing an LNG terminal in the port of Gothenburg.

Swedegas, which owns and operates the gas grid in southwestern Sweden, will partner Vopak have launched a technical feasibility study with the aim of taking of a final investment decision on the project early next year, a Swedegas spokesperson said.

Swedegas is hoping to start operations at the terminal in 2015, which would have an initial regasification capacity of around 500 million cubic meters/year, although this could be expanded depending on future demand, according to the Swedish company.

Currently, Sweden imports all its natural gas from Denmark via a pipeline that links the two countries. The available import capacity of the Swedish transmission system is 30TWh/year (around 2.80 billion cubic meters/year) of natural gas. Last year Swedegas transported energy equivalent to 15TWh in the system, and the company is keen to develop the LNG terminal as a means to tap into the growing market for LNG as a shipping fuel but also to supply industrial and commercial end-users that are not connected to the grid.

Sweden already has a small-scale LNG terminal opened by industrial gas manufacturer AGA in May 2011 in Nynäshamn in the east of the country. A further terminal is being developed by regional small-scale LNG supplier Skangass on the country's west coast at Lysekil.

Unlike the terminal at Lysekil, the prospective LNG terminal at Gothenburg will be open to all companies that are interested in supplying the Swedish gas market, Swedegas said.

"The one in Lyeskil is a different business approach," the spokesperson said. "They [Skangass] own the tank, operate and supply the LNG to one major customer. We would look to invest in an open-access terminal where commercial actors can buy capacity in the tank."

RUSSIA

Gazprom Mulls New Partners for Revamped Shtokman Project

Russian gas giant OAO Gazprom is considering finding new partners to develop its Shtokman field off the Russian Arctic as it seeks to turn it into a full liquefied natural gas project, its vice chairman, Alexander Medvedev, said June 6.

Mr. Medvedev said the current partners--Norway's Statoil ASA and France's Total SA, which have stakes in the project's consortium of 24% and 25%, respectively--had "good chances" of remaining.

He also said he had "a good idea" of who Gazprom's new partners could be but he declined to say.

Gazprom has been seeking to develop Shtokman, one of the world's largest natural gas fields, since the early 1990s, and after several attempts has put together a consortium comprising Statoil, Total and itself. But technological challenges and precipitously low gas prices, as well as the emergence of the U.S. as a gas exporter, have called its financial viability into question. The final investment decision for project hasn't been announced.

The three partners have extended negotiations until June 30, and the past weeks have been rife with rumors of Statoil dropping out of the project.

Also on June 6, in an interview with Dow Jones Newswires, Statoil Vice President Eldar Saetre said his company remained fully committed to the project and that he hoped it would go through after having received "positive signals" from the Russian authorities on the financial framework.

"Our decision to switch Shtokman to a full LNG project reflects our vision for gas demand and supply," Mr. Medvedev said, speaking to reporters on the sidelines of an industry conference.

Initially, half of the gas extracted at Shtokman was supposed to be sent to the U.S. and Europe via pipelines.

Gazprom also hopes to send gas via pipeline to China, through what is called the western corridor, and Russian President Vladimir Putin was in Beijing in early June, attempting to rekindle the talks.

The parties have failed to agree on a start-up price, Mr. Medvedev said, noting that "the gas market in China is quite subsidized" while there is also competition from domestic gas production.

Gazprom and China National Petroleum Corp. signed a framework agreement in 2009 to transport 70 billion cubic meters of Russian gas annually to China through two pipelines, one running into western China and the other to the east of the country.

Gazprom wants gas prices similar to those it receives in Europe, while CNPC is holding out for a discount.

Pricing is especially sensitive for CNPC, because it faces government price controls on natural gas sold in the domestic Chinese market.

The company is paying European-level prices for natural gas imported via pipeline from Turkmenistan, meaning it is likely selling at a loss in the domestic market, according to analysts.

Qatar Petroleum Interested in Yamal LNG Stake

Qatar Petroleum is interested in securing a stake in the Yamal LNG project in the Arctic as well as a stake in independent Russian gas producer Novatek, a move that would match the world's leading LNG exporter with the world's unchallenged natural gas power.

"Qatar is interested in being a partner in the Yamal project and not only did we show our interest but we have already been engaged in the process and we created a team through Qatar Petroleum International to be fully engaged in the negotiation of partnership in Yamal LNG," says Qatar's oil minister Mohammed Al Sada.

It was the first confirmation by Qatar that it was seriously considering the proposal to join the Yamal LNG consortium of Novatek and France's Total.

"We are working very hard and the partners have allowed enough resources," he says. "All partners, from what I gather, specifically I can talk about Qatar, are interested in concluding the deal as soon as possible."

Total and Novatek signed two memoranda of cooperation in October that would give Total a 12.08 per cent stake in Novatek and a 20 per cent stake in Novatek's Yamal LNG project, a 15 million tonnes per year (mtpy) plant to be built on the Yamal Peninsula in northwestern Siberia.

"We are interested in both, in Yamal as well as in Novatek, and we are engaged in the discussions on these two projects at the same time," Al Sada said. Qatar is the world's biggest LNG exporter with current production capacity of 77 mtpy.

Total and Novatek are seeking a new partner for the high-cost project and Russian energy minister Sergei Shmatko has been pressing the Russian case for Qatari participation in Doha in recent days.

He says Qatar could bring in its expertise in liquefaction technology, transport and marketing as well as finance for the project, which Novatek has estimated will cost $15-$20 billion. A final investment decision is due to be made at the end of 2012.

Al Sada was asked why Qatar, which produces LNG in a low-cost area with feedstock from the prolific North field, would be interested in investing in a high-cost project.

"Qatar is interested in investing outside Qatar and this is a project which is in line with our investment strategy and in line with our strengths and expertise," he says.

Al Sada says Qatar, which has imposed a moratorium on further development of the 900 tcf North field, the biggest concentration of non-associated gas in the world, is looking to expand its presence abroad. "These are long-term projects and we look at this project through the life cycle of the project. We believe it is a good project," he says.

He said that while QPI is studying a number of projects, it has no "geographic preference." These include upstream exploration as well as petrochemicals and other projects in Asia and elsewhere.

"Right now we are focusing on these projects," Al Sada says when asked if Qatar was looking to invest in other Russian energy projects.

"We have an excellent relationship with the Russian companies and we are open to look at any proposal be it in Russia or outside. We are very much open to the Russians and other companies, especially companies known to us such as Gazprom.

We are partners here in Qatar and we are interested in partnering with them outside as well."

Novatek says it expected to choose more than one international partner for the Yamal LNG project by year-end, with the company keeping at least a 51 per cent stake. Other potential foreign partners named have included Shell, ExxonMobil, ConocoPhillips, Mitsui, Mitsubishi, Malaysia's Petronas, India's state-owned ONGC and Repsol of Spain.

A partnership between Qatar and Russia would bring together the world's biggest LNG producer and the biggest producer of natural gas globally, though both countries are competing for a bigger share of the European market, where Russia is dominant through its pipeline gas sales, recently bolstered by the launch of the Nord Stream pipeline across the Baltic to Germany.

But Russia is now aspiring to become a major LNG player during the current decade from its Sakhalin 2 plant and Yamal once it is operational. This would put both Russia and Qatar in competition with Australia, which is set to become the second-biggest LNG producer after Qatar once its own massive liquefaction plants are completed.

"The reserves of gas in Yamal are the largest in the world," Russia's Shmatko says. "In five or six years, Russia will be a major actor in the LNG market" and would welcome bilateral and trilateral cooperation in its projects.

Al Sada says that Qatar is studying Yamal's marketing strategy as part of its appraisal of the project. Some analysts have said they believe Yamal LNG's market is more likely to be southern Europe rather than the Asian market given its location above the Arctic Circle.

Qatar already supplies LNG to Europe through its Adriatic terminal and the UK's South Hook and has been seeking to increase its market share in Europe as exports to the U.S. have fallen as a result of rising shale gas production there.

The Qatari minister at a news conference earlier did not respond specifically to remarks by Shmatko that Doha would cut its exports to Europe in the medium to long term. But he did say that Qatar had no intention of curbing its exports in the short term.

Al Sada says Qatar would export the gas "to where the market needs it. Today, the Asian market definitely has more potential for gas. In the future we will see some other areas that show more appetite for gas, South America for example."

Shell May Become Top Foreign Partner in Russia's Shtokman Project

Norway's Statoil, Gazprom, and Royal Dutch Shell will start negotiations during the last week in June over the latter joining the Shtokman project , the huge gas deposit in the Russian Arctic, as the leading foreign investor, a Gazprom source told PRIME June 21.

"Statoil has sent a letter to Gazprom saying that it is ready to participate in the partnership of the Shtokman project, where Shell will be the core foreign partner, and suggested Gazprom start trilateral talks on the issue," the source said on the sidelines of the St. Petersburg International Economic Forum.

"The proposal was discussed during the St. Petersburg Economic Forum, and Gazprom agreed to hold such trilateral talks next week, given that the term of the current agreement is about to expire."

The partners in Shtokman, with reserves of almost four trillion cubic meters of gas, have been unable to reach an investment decision and the protracted talks led to speculation about the possibility of the project being dissolved.

Shtokman, with its dangers of high sea waves, bitterly cold weather, and huge icebergs, requires an initial investment of U.S. $15 billion.

The signing of a new agreement was one of the most expected events of the forum, but Gazprom CEO Alexei Miller said it will not happen. He has also said that the company was in talks with several firms over joining Shtokman. Gazprom's share is not supposed to change as a result.

Gazprom has a controlling stake of 51% in Shtokman, Statoil owns 24%, and Total 25%.

Also on June 21, Total CEO Christophe de Margerie said he hopes that all the differences over the project will be ironed out by the end of June.

Shtokman, located 550 kilometers off the shores of Russia, still plans to begin gas supplies to Europe via the Nord Stream pipeline in 2016 and start shipping liquefied natural gas around the world from 2017. The first exploration well was drilled in 1988.

Shell is already working with Gazprom on the Sakhalin-2 project, Russia's sole LNG plant. Gazprom clinched a $7.45 billion deal in 2006, following months of pressure from Russian officials to buy half of Sakhalin-2 from Shell and its partners, as the Kremlin tightened its grip on Russia's energy sector.

Shell and Gazprom have also been in talks about the Russian company joining the Anglo-Dutch major's foreign oil and gas projects, although no specific projects have yet been named.

ARCTIC

Qatar Petroleum Interested in Yamal LNG Stake

It was the first confirmation by Qatar that it was seriously considering the proposal to join the Yamal LNG consortium of Novatek and France's Total.

"We are working very hard and the partners have allowed enough resources," he says. "All partners, from what I gather, specially I can talk about Qatar, are interested in concluding the deal as soon as possible."

Total and Novatek are seeking a new partner for the high-cost project and Russian energy minister Sergei Shmatko has been pressing the Russian case for Qatari participation in Doha in recent days.

Al Sada was asked why Qatar, which produces LNG in a low-cost area with feedstock from the prolific North field, would be interested in investing in a high-cost project.

"Qatar is interested in investing outside Qatar and this is a project which is in line with our investment strategy and in line with our strengths and expertise," he says.

He said that while QPI is studying a number of projects, it has no "geographic preference." These include upstream exploration as well as petrochemicals and other projects in Asia and elsewhere.

"Right now we are focusing on these projects," Al Sada says when asked if Qatar was looking to invest in other Russian energy projects.

We are partners here in Qatar and we are interested in partnering with them outside as well."

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