U.S. and Japan Complete Successful Field Trial of Methane Hydrate Production Technologies

U.S. Energy Secretary Steven Chu announced on May 2 the completion of a successful, unprecedented test of technology in the North Slope of Alaska that was able to safely extract a steady flow of natural gas from methane hydrates – a vast, entirely untapped resource that holds enormous potential for U.S. economic and energy security. Building upon this initial, small-scale test, the Department is launching a new research effort to conduct a long-term production test in the Arctic as well as research to test additional technologies that could be used to locate, characterize and safely extract methane hydrates on a larger scale in the U.S. Gulf Coast.

"The Energy Department’s long term investments in shale gas research during the 70s and 80s helped pave the way for today’s boom in domestic natural gas production that is projected to cut the cost of natural gas by 30 percent by 2025 while creating thousands of American jobs," said Secretary Chu. "While this is just the beginning, this research could potentially yield significant new supplies of natural gas."

Methane hydrates are 3D ice-lattice structures with natural gas locked inside, and are found both onshore and offshore – including under the Arctic permafrost and in ocean sediments along nearly every continental shelf in the world. The substance looks remarkably like white ice, but it does not behave like ice. When methane hydrate is "melted," or exposed to pressure and temperature conditions outside those where it is stable, the solid crystalline lattice turns to liquid water, and the enclosed methane molecules are released as gas.

The Department of Energy has partnered with ConocoPhillips and the Japan Oil, Gas and Metals National Corporation to conduct a test of natural gas extraction from methane hydrate using a unique production technology, developed through laboratory collaboration between the University of Bergen, Norway, and ConocoPhillips. This ongoing, proof-of-concept test commenced on February 15, 2012, and concluded on April 10. The team injected a mixture of carbon dioxide (CO2) and nitrogen into the formation, and demonstrated that this mixture could promote the production of natural gas. Ongoing analyses of the extensive datasets acquired at the field site will be needed to determine the efficiency of simultaneous CO2 storage in the reservoirs.

This test was the first ever field trial of a methane hydrate production methodology whereby CO2 was exchanged in situ with the methane molecules within a methane hydrate structure. As part of this exchange demonstration, the depressurization (i.e., production through decreasing pressure of the deposit) phase of the test extended for 30 days. The prior longest-duration field test of methane hydrate extraction via depressurization was six days (Japan-Canada 2007/2008 Mallik well testing program).

This testing will provide critical information to advance the Department’s efforts to evaluate various potential gas hydrate production technologies. The next stages of the Department’s research effort will be aimed in part at evaluating gas hydrate production over longer durations, likely through depressurization, with the eventual goal of making sustained production economically viable. While this may take years to accomplish, the same could be said of the early shale gas research and technology demonstration efforts that the Department backed in the 1970s and 1980s.

The Department is announcing two major new steps in the overall methane hydrate research effort:

1) The Department is making $6.5 million available in Fiscal Year 2012 Funding Opportunity Announcement for research into technologies to locate, characterize and safely extract natural gas from methane hydrate formations like those in the Arctic and along the U.S. Gulf Coast. Specifically, projects will address (1) deepwater gas hydrate characterization via direct sampling and/or remote sensing field programs; (2) new tools and methods for monitoring, collecting, and analyzing data to determine reservoir response and environmental impacts related to methane hydrate production; and (3) clarifying methane hydrates role in the environment, including responses to warming climates.

2) As part of the President’s budget proposal for Fiscal Year 2013, the Department is requesting an additional $5 million to further gas hydrates research both domestically, and in collaboration with international partners. The exact nature of that research effort will be determined in the coming months; however, a longer duration test of methane hydrate extraction on the North Slope on an existing gravel bed pad that can accommodate year-round operations is envisioned. Such an effort would again require engaging private sector and international partners.

Oregon LNG, which had proposed an LNG import project near Astoria, OR, has sent signals to federal agencies that it plans to join several other U.S. terminal developers in building liquefaction facilities that would give its terminal export capability.

"They've informally notified FERC and other federal agencies of their plans to enter the prefiling process with FERC, but they have not officially done so yet," FERC spokeswoman Tamara Young-Allen said in an interview late March 28.

If Oregon LNG does introduce such a project, it would join a similar export proposal by Jordan Cove Energy Project LP that would be farther south on the Oregon coast. If both are built, the terminals would be the only two export facilities on the West Coast below Alaska.

The subject of "potential modifications" to the Oregon LNG project has come up in correspondence between FERC and the National Marine Fisheries Service, part of the National Oceanic and Atmospheric Administration within the U.S. Department of Commerce. In a March 28 letter, FERC told the NMFS it was withdrawing its request for Endangered Species Act consultation because Oregon LNG and Oregon Pipeline Co., the affiliated company behind the takeaway pipeline for the LNG proposal, planned "to use the commission's pre-filing review process to modify their projects ... in the near future." FERC said it would file a new request for consultation "at the appropriate time."

The FERC letter followed a March 6 letter from NMFS to FERC, in which NMFS said if it did not hear from the commission in 30 days it would assume the import project had been withdrawn and would close its file. "FERC has not issued a scheduling notice for the project, and the proposed action remains in development," NMFS wrote in its letter. "We understand that several issues have delayed project progress, including vapor dispersal modeling, legal action, and potential modifications to the project purpose."

The original proposal for the Oregon LNG import terminal and the takeaway pipeline have run into long delays, which in a 2010 interview Hansen blamed on bureaucracy and the opposition of "radical, anti-development group" Columbia Riverkeeper.

The LNG market is growing and its future looks good. Some industry analysts predict demand for LNG globally will increase 40% in the five year period from 2010 to 2015. This would make the annual market for LNG roughly 300 million tons. The U.S. has the fifth highest amount of natural gas reserves in the world with the EIA putting the number at 273 trillion cubic feet. By comparison Australia has the 12th highest natural gas reserves with only 110 trillion cubic feet.

Australia was able to ship more than 12 times as much LNG overseas in 2010 than the U.S. The largest obstacle the U.S. faces in the LNG market is its lack of export/liquefaction terminals. With the Kenai facility going idle the Sabine Pass terminal is the only facility in America even close to being able to regularly send LNG overseas. And even that could still be a few years away. Now what about building LNG liquefaction plants?

Unit Economics says it can cost $3 billion for each million tons of annual capacity for the entire liquefaction supply chain which includes production pipelines the port and the facility itself. The Wall Street Journal reports there are seven additional projects seeking approval from the Department of Energy to ship LNG to most foreign nations. If all of these projects gain approval they could handle about 25 percent of U.S. gas production.

However the news source reports that approval for all of the facilities is unlikely. An additional hurdle to the LNG market in the U.S. is political opposition to sending the energy source overseas. The American Chemistry Council has warned the U.S. government that it should not undermine the availability of domestic natural gas but is not necessarily against exporting the substance. The Sierra Club is concerned that exporting more natural gas will cause companies to increase their fracking operations.

While there has been little to no evidence that fracking itself harms the environment a groundswell of opposition to the practice has emerged making investing in greater production difficult for the industry. In spite the hurdles in exporting LNG the U.S. also has many opportunities. In mid March Japanese officials planned to meet with a delegation headed by Deputy Energy Secretary Daniel Poneman to reportedly request LNG exports to Japan.

This appears to be a major step as Japan had previously shied away from American LNG due to uncertainty over whether Washington would allow it to be exported. As stated Japan’s thirst for LNG will only grow stronger as the country scales back on its use of nuclear power following last year’s Fukushima Daiichi nuclear disaster. Before the disaster nuclear power accounted for about 30 percent of Japan s energy production. Japan will need to fill the void that was left in it’s wake.

Other markets that could be exploited by the U.S. are the U.K. France and Spain all three of which are among the largest importers of LNG in the world. While Australia does send some LNG to these European countries most of the U.S. competition will come from African countries like Nigeria and Algeria as well as Qatar.

Another positive sign for U.S. LNG exports is that they appear to have the support of Energy Secretary Steven Chu who has stated that sending the hydrocarbon overseas would allow America to cut into its trade deficit. He said exporting natural gas means wealth coming into the United States reports The Wall Street Journal.

There is much work to be done in the U.S. LNG industry to help it catch up with Australia but the economics will be powerful if it does. The gears are in motion as both international markets are opening up domestic production increases and LNG liquefaction facilities gain approval and come on line.

Currently, the Sabine Pass boasts regasification and send-out capacity of 4.0 billion cubic feet per day (Bcf/d) and storage capacity of 16.9 billion cubic feet equivalent (Bcfe).

The U.S. Federal Energy Regulatory Commission (FERC) has granted Cheniere Energy Partners, L.P. authorization to site, construct and operate facilities to liquefy and export domestically produced natural gas at the Sabine Pass LNG terminal in Cameron Parish, La., Cheniere Partners announced April 16.

"Obtaining approval from the FERC is one more milestone for our Liquefaction Project," said Cheniere Chairman and CEO Charif Souki in a company statement.

"We will now finalize the financing arrangements in order to commence construction of the first two LNG trains of our Liquefaction Project promptly."

FERC's order authorizes the development of up to four modular LNG trains at Cheniere Partners' 100-percent owned Sabine Pass LNG terminal, which is located on the Sabine Pass Channel in the southwestern corner of Louisiana. Each train would possess a nominal capacity of 4.5 million tons per annum (mtpa). Currently, the Sabine Pass boasts regasification and send-out capacity of 4.0 billion cubic feet per day (Bcf/d) and storage capacity of 16.9 billion cubic feet equivalent (Bcfe).

Cheniere Partners anticipates building each liquefaction train 6 to 9 months after the previous train. Construction could begin as soon as the second quarter of this year, with operations commencing in 2015/2016. Last November, Cheniere Partners' Sabine Liquefaction subsidiary awarded Bechtel Oil, Gas and Chemicals, Inc. a lump sum turnkey contract for the engineering, procurement and construction (EPC) of the first two trains.

Sabine Liquefaction has also entered into four long-term customer sale and purchase agreements (SPA) for 16.0 mtpa of LNG volumes -- equating to approximately 89 percent of the nominal LNG volumes. The customers include BG Gulf Coast LNG, LLC (5.5 mtpa); Gas Natural Fenosa (3.5 mtpa); KOGAS (3.5 mtpa) and GAIL (India) Ltd. (3.5 mtpa). The BG and Gas Natural Fenosa SPAs commence with the start of operations for trains 1 and 2, respectively. Cheniere Partners said that construction of the first two trains hinges on, among other things, obtaining financing and making a final investment decision.

In a related announcement on April 16, Cheniere Partners said that it has engaged eight financial institutions to act as joint lead arrangers to assist in structuring and arranging of up to $4 billion of debt facilities. Proceeds would pay for the costs of developing and constructing the first two trains as well as funding the acquisition of the Creole Trail Pipeline from Cheniere Energy, Inc. for general business purposes. Cheniere Partners estimates $4.5 to $5.0 billion in pre-financing capital costs for trains 1 and 2 that would be funded with debt and equity.

"Obtaining financing is one of the last steps to complete before proceeding with the construction of the first two liquefaction trains being developed at the Sabine Pass LNG terminal," said Souki. "We have engaged an experienced group of financial institutions as our core banking group and look forward to completing the financing for the project in due course."

The eight arrangers are The Bank of Tokyo-Mitsubishi UFJ, Ltd., Credit Agricole Corporate and Investment Bank, Credit Suisse Securities (USA) LLC, HSBC, J.P. Morgan Securities LLC, Morgan Stanley, RBC Capital Markets, and SG Americas Securities, LLC.

The KOGAS and GAIL SPAs will commence with the start of operations for trains 3 and 4, respectively. Construction of these trains, which could begin next year, would follow milestones including entering into an EPC contract, obtaining regulatory approvals, obtaining financing and making a final investment decision. Trains 3 and 4 could begin operations in the 2017/2018 time frame.

Cheniere Partners has posted various documents related to the Sabine Liquefaction Project on its website.

Cheniere Partners estimates the project will support 3,000 jobs during the peak of construction and 150 jobs during operations at all four trains.

In 2003, Houston-based Cheniere Energy decided to build a big terminal to import natural gas. At the time, domestic gas production was in decline, prices were high and the U.S. faced shipping in large quantities of liquefied natural gas to meet rising demand.

That is not how things turned out. As Jean Abiteboul, Cheniere’s head of marketing said, "We made the same mistake as others. We underestimated the magnitude of shale gas."

While Cheniere built its LNG terminal, the oil industry was unlocking the vast reserves of gas trapped in dense shale rocks that stretch from Pennsylvania to Texas. Techniques such as "fracking" and horizontal drilling triggered a production boom. Thanks to shale, the U.S. in 2010 overtook Russia as the world’s largest gas producer.

With shale causing an unexpected supply glut in the U.S., Cheniere, which started as a small oil explorer, made a radical decision: instead of importing LNG, it would export it. This about-face highlights the size of a revolution that has transformed America’s energy outlook and how the repercussions of that boom are beginning to be felt far beyond the U.S..

Cheniere is one of a number of companies that plan to export surplus U.S. gas – and at much lower prices than those set by other producers. For global energy markets, that is a change of potentially huge proportions. "This is going to have big implications for traditional exporters of gas," says Fatih Birol, chief economist at the International Energy Agency, the west’s industry monitor. "All of them are worried. They have a competitor entering the market that produces gas at much lower cost."

This development could recast a world gas trade long dominated by a handful of energy superpowers – countries including Russia, Qatar and Algeria. The pipelines that connect Russia’s west Siberian fields with consumers in Europe and the LNG tankers that make their way from the Gulf and south-east Asia to Japan have created a network of dependency that has evolved over generations.

Those relationships are now facing an unprecedented challenge. From the UK to Argentina, from South Africa to Mexico, countries are realizing the potential value of domestic shale gas reserves. A new wave of gas producers looks set to emerge that could threaten the old system.

The changes mean that for producers such as Gazprom of Russia the future looks a lot less certain than it did a decade ago. Some of its customers, such as Poland, are exploring unconventional deposits that could drastically reduce their reliance on Russian imports. China, too, has so much of its own shale gas that it could ditch long-standing plans to import big amounts from Russia through a new pipeline from Siberia.

The geopolitical fallout will stretch out over decades. What will have a more immediate impact on global markets is the way U.S. exports of gas are being priced.

For decades, LNG has been sold under 20-year contracts indexed to the price of oil. Cheniere’s export contracts are linked instead to U.S. gas prices, which have been driven to 10-year lows by the shale gas glut. Cheniere’s deals are a "major milestone", says Jonathan Stern, professor at the Oxford Institute for Energy Studies, part of Oxford university. "For the first time, someone with a real project and real customers is saying, We can sell LNG to Asia on a different basis – that is, not indexed to the price of oil’."

A Sempra Energy unit, Cameron LNG, on April 17 announced that the company has signed commercial development agreements with Mitsubishi Corporation and Mitsui & Co., Ltd. to develop and construct a natural gas liquefaction export facility at the site of Cameron LNG receipt terminal in Hackberry, La.

The commercial development agreements bind the parties to fund all development expenses, including design, permitting and engineering, as well as to negotiate 20-year tolling agreements, based on agreed-upon terms outlined in the commercial development agreements. Each tolling agreement would be for 4 million tonnes per annum (Mtpa). Negotiations with other parties for the export of the remaining 4 Mtpa are ongoing.

The completed liquefaction facility is expected to be comprised of three liquefaction trains with a total export capability of 12 Mtpa of liquefied natural gas (LNG), or approximately 1.7 billion cubic feet (Bcf) per day. Construction on the project is expected to start in late 2013 with operations to commence in late 2016.

"These agreements with Mitsubishi and Mitsui represent a significant step forward in the development of a liquefaction facility at our Louisiana LNG terminal to support international natural gas markets," said Mark A. Snell, president of Sempra Energy.

The liquefaction facility will utilize Cameron LNG's existing facilities, including two marine berths capable of accommodating Q-Flex sized LNG ships, three LNG storage tanks of 480,000 cubic meters, and vaporization capability for regasification services of 1.5 Bcf per day. The anticipated incremental investment in the three-train liquefaction project is estimated to be $6 billion, the majority of which will be project-financed and the balance provided by the project partners in a joint-venture arrangement.

"We look forward to supporting Mitsubishi's and Mitsui's objectives to develop North American gas resources and deliver LNG to worldwide markets through a tolling arrangement at our facility," said Octavio M. Simoes, president of Sempra Energy's LNG operations.

In January 2012, Cameron LNG received approval from the U.S. Department of Energy (DOE) to export up to 12 Mtpa of domestically produced LNG from the Cameron LNG terminal to all current and future Free Trade Agreement countries. The authorization to export LNG to countries with which the U.S. does not have a Free Trade Agreement is pending review by the DOE. Cameron LNG expects to receive the required permits from the Federal Energy Regulatory Commission (FERC) and enter into a turnkey contract in 2013 for engineering and construction services for the project.

Cameron LNG has awarded an engineering services contract to Foster Wheeler AG for project development, front-end engineering design to support permit applications to the FERC and support for engineering and construction contracting. Additionally, Cameron LNG has engaged the international law firm Morgan Lewis & Bockius LLP as legal counsel for the development of the liquefaction project and The Royal Bank of Scotland as financial advisor for the liquefaction project.

Sempra Energy's subsidiaries operate two LNG receipt terminals in North America -- Energia Costa Azul near Ensenada, Mexico, and Cameron LNG.

Sempra International, LLC, and Sempra U.S. Gas & Power, LLC, are not the same companies as San Diego Gas & Electric (SDG&E) or Southern California Gas Company (SoCalGas) and Sempra International and Sempra U.S. Gas & Power are not regulated by the California Public Utilities Commission.

Note: Formerly known entities Sempra Generation, Sempra LNG and Sempra Pipelines & Storage have now been realigned under Sempra International and Sempra U.S. Gas & Power.

In response to a court deadline, the U.S. Environmental Protection Agency (EPA) has finalized standards to reduce harmful air pollution associated with oil and natural gas production. The updated standards, required by the Clean Air Act, were informed by the important feedback from a range of stakeholders including the public, public health groups, states and industry. As a result, the final standards reduce implementation costs while also ensuring they are achievable and can be met by relying on proven, cost-effective technologies as well as processes already in use at approximately half of the fractured natural gas wells in the United States. These technologies will not only reduce 95 percent of the harmful emissions from these wells that contribute to smog and lead to health impacts, they will also enable companies to collect additional natural gas that can be sold. Natural gas is a key component of the nation’s clean energy future and the standards released today make sure that we can continue to expand production of this important domestic resource while reducing impacts to public health, and most importantly builds on steps already being taken by industry leaders.

"The president has been clear that he wants to continue to expand production of important domestic resources like natural gas, and today’s standard supports that goal while making sure these fuels are produced without threatening the health of the American people," said EPA Administrator Lisa P. Jackson. "By ensuring the capture of gases that were previously released to pollute our air and threaten our climate, these updated standards will not only protect our health, but also lead to more product for fuel suppliers to bring to market. They're an important step toward tapping future energy supplies without exposing American families and children to dangerous health threats in the air they breathe."

When natural gas is produced, some of the gas escapes the well and may not be captured by the producing company. These gases can pollute the air and as a result threaten public health. Consistent with states that have already put in place similar requirements, the updated EPA standards released today include the first federal air rules for natural gas wells that are hydraulically fractured, specifically requiring operators of new fractured natural gas wells to use cost-effective technologies and practices to capture natural gas that might otherwise escape the well, which can subsequently be sold. EPA’s analysis of the final rules shows that they are highly cost-effective, relying on widely available technologies and practices already deployed at approximately half of all fractured wells, and consistent with steps industry is already taking in many cases to capture additional natural gas for sale, offsetting the cost of compliance. Together these rules will result in $11 to $19 million in savings for industry each year. In addition to cutting pollution at the wellhead, EPA’s final standards also address emissions from storage tanks and other equipment.

Also in line with the executive order released by the president on natural gas development, the rule released April 18 received important interagency feedback and provides industry flexibilities. Based on new data provided during the public comment period, the final rule establishes a phase-in period that will ensure emissions reduction technology is broadly available. During the first phase, until January 2015, owners and operators must either flare their emissions or use emissions reduction technology called "green completions," technologies that are already widely deployed at wells. In 2015, all new fractured wells will be required to use green completions. The final rule does not require new federal permits. Instead, it sets clear standards and uses enhanced reporting to strengthen transparency and accountability, and ensure compliance, while establishing a consistent set of national standards to safeguard public health and the environment.

An estimated 13,000 new and existing natural gas wells are fractured or re-fractured each year. As those wells are being prepared for production, they emit volatile organic compounds (VOCs), which contribute to smog formation, and air toxics, including benzene and hexane, which can cause cancer and other serious health effects. In addition, the rule is expected to yield a significant environmental co-benefit by reducing methane, the primary constituent of natural gas. Methane, when released directly to the atmosphere, is a potent greenhouse gas—more than 20 times more potent than carbon dioxide.

During the nearly 100-day public comment period, the agency received more than 150,000 comments on the proposed rules from the public, industry, environmental groups and states. The agency also held three public hearings. The updated standards were informed by the important feedback received through the public comment period, reducing implementation cost and ensuring the achievable standard can be met by relying on proven, cost-effective technologies and processes already in use.

More information: http://www.epa.gov/airquality/oilandgas

Foster Wheeler AG announced April 27 that a subsidiary of its Global Engineering and Construction Group has been awarded an owner's engineer contract for a new LNG liquefaction project to be located in Hackberry, Louisiana, by Cameron LNG LLC, an affiliate of Sempra Energy, planned to export up to 12 million tons per annum of LNG.

The Foster Wheeler contract value for this project was not disclosed, and an initial booking was included in the company's fourth-quarter 2011 bookings, with the main releases of work expected to follow in 2012.

Foster Wheeler's scope of work includes technical assistance for project development, the execution of front-end engineering to support permit applications to the U.S. Federal Energy Regulatory Commission, development of technical specifications and invitation to bid packages for engineering, procurement and construction activities, and technical reviews. The work will also include integration with existing Cameron LNG facilities and may include additional scopes of work as the project develops.

"We are pleased that Cameron LNG has selected Foster Wheeler to fulfill the role of owner's engineer up to the EPC phase of the project," said Umberto della Sala, Chief Operating Officer of Foster Wheeler AG. "With our proven track record of executing safe, successful LNG liquefaction projects, we are well positioned to respond to opportunities provided by the drive to monetize gas resources in the U.S. market."

Argentina's state oil company Enarsa has launched a new LNG tender and planned to open offers on April 12, a close source told BNamericas.

The tender is for shipments of LNG to be delivered to the Bahía Blanca and Escobar plants between May and August, according to international press reports.

The country's increasing reliance on imported fuel has prompted the government to put pressure on the oil and gas sector to increase domestic production.

Earlier this year President Cristina Fernández called on oil companies to reinvest in Argentina, saying the country imported US$9bn worth of fuel in 2011 - up 110% from 2010.

"In 2011 the energy sector saw a trade deficit of US$4.5bn, and this year it's likely to double," the country's former energy secretary Emilio Apud said in a February interview with BNamericas.

The government has paid around US$16/MBTU for LNG imports while price restrictions, in place since the 2001 economic crisis, mean domestically produced gas sells at approximately US$2.50/MBTU.

The price discrepancy has been a bone of contention for many industry players, but Argentina's power system relies on gas-fired plants for more than half its generating capacity so the government has little choice but to pay the market price.

At the same time, the state has demanded a 15% production increase from locally operating companies over the next two years and is withdrawing concession licenses which are found to be lacking in investment and production.

Sanctions have centered on Spanish firm Repsol's local branch YPF, leading to speculation that the government is aiming to devalue the firm in advance of an aggressive takeover.

The provincial government of Santa Cruz is the latest to move against the firm, announcing that it intends to strip licenses in the areas Cañadón Vasco, Pico Truncado-El Cordón and Los Perales.

Santa Cruz is the company's highest producing province, with 31% of total production, the authority statement said.

Meanwhile, YPF said in a statement on April 9 that Repsol CEO Antonio Brufau has formally requested a meeting with the federal government.

Chilean generator and gas distributor GasAtacama plans to submit an EIA for the construction of the country's third LNG regasification facility near the town of Mejillones in northern region II before the end of April, the firm's managing director Rudolf Araneda told BNamericas.

"[We expect] to deliver the EIA within the next week. There is no fixed time period for how long it will take to have it approved. We are predicting a date of 2016 to start operations, to give us sufficient construction time," Araneda told BNamericas.

"Investments in the project are large. We require the use of an LNG carrier, that's in the range of US$200mn-250mn, and an FRSU of between US$250mn-300mn. Upfront costs we expect therefore to be in the range of US$500mn."

According to the executive, Chile's maritime authorities have already approved the company's plans to install a floating storage and regasification unit (FRSU) 2km off the coast in Mejillones bay, connecting to the firm's 780MW Central Térmica Atacama thermo plant through an underwater pipeline.

Shipments into the FRSU will be used to meet power demand from expanding mining operations on the SING grid. Demand on the SING is expected to double over the course of the next 10 years. GasAtacama hopes to begin supplying the new mining facilities as they come online from 2016 onwards.

"By the middle of this year we'll have a firm basis of gas supply, boat supply and a floating regasification unit organized so that we can go to the mining companies to offer them contracts," Araneda said.

According to Araneda the company is currently in discussions with gas providers from both Europe and the U.S. in the hope of sorting an agreement before the end of May.

Supply contracts of up to 20 years with a value in excess of US$5bn are envisaged by the Chilean firm.

Excess gas could also be used to the meet the demands of some of GasAtacama's residential and industrial customers, as well as other power generators such as parent company Endesa Chile.

The government of Uruguay is likely to continue the development of an LNG regasification plant off the coast of capital Montevideo on its own, should Argentina's government decide to pull out of the project, a senior source at the former country's state power company UTE told BNamericas.

UTE and its sister firm, state oil company Ancap, are managing the project on behalf of the Uruguayan government through the Gas Sayago JV, along with Argentina's state power firm Enarsa.

However, recent speculation in the Uruguayan press suggests that Argentine authorities are considering pulling out of the GNL del Plata project.

"It's the intention of our government to have the regasification plant by whatever means. I think it will still be possible if we can secure a gas sales contract with Argentina," the source told BNamericas.

Recent gas shortages across Argentina make the likelihood of a sales contract likely, according to analysts.

Under present proposals, first phase production at the plant would be 10Mm3/d, equally distributed between the two countries, with maximum capacity reaching 15Mm3/d.

A tender for construction of the plant is expected later this year, and the parties involved have predicted that the plant will be online in 2014.

Gas Sayago sources have previously put costs on the Uruguayan side at US$400mn. Similar investment levels had also been anticipated from the government of Argentina.

In related news, Ancap has formally signed an agreement with Argentina's largest oil firm YPF, under which the latter will conduct oil exploration across a 10,000km2 area in the departments of Artigas, Salto, Tacuarembó and Rivera.

The one-year contract will allow YPF to conduct small-scale surveys before it then decides whether to move on to further exploration phases which could include drilling.

YPF now joins U.S. firm Schuepbach Energy in conducting exploration work onshore Uruguay.

2. ASIA

General Electric Co. is seeking $6 billion in contracts out of Australia by the end of the decade as it taps the country’s growing role as a supplier of liquefied natural gas, iron ore and wind power.

"We see a really significant opportunity set here," John Anderson, senior regional executive overseeing GE’s energy business in Australia, New Zealand and Papua New Guinea, said in a telephone interview from Melbourne.

Growth areas such as Australia may account for half of GE’s industrial revenue by 2020, up from 37 percent of its $94 billion in industrial sales last year, the company has said. GE’s sales in Australia of equipment for customers ranging from energy producers to mining companies rose 67 percent to almost $3 billion last year, outpacing China and Latin America.

The Fairfield, Connecticut-based company is involved in all the LNG projects being built in Australia and will bid for more contracts as the industry expands, Anderson said in his first interview since accepting the new role in January. With $180 billion of LNG projects advancing, Australia is set to surpass Qatar as the largest exporter of the fuel by the end of the decade, according to Sanford C. Bernstein & Co.

"There’s a significant prize to be had for both maintaining that position and expanding it," said Anderson, who received degrees from the University of Western Australia and Curtin University and returned to Australia following a 25-year career at BP Plc mostly in the UK and the U.S.

BG Group Plc (BG/), ConocoPhillips and Santos Ltd. are going ahead with more than $50 billion of LNG developments on the coast of central Queensland in Australia’s northeast for fuel exports to Asia. Those projects may expand.

GE opened a $100 million service and maintenance facility in Perth last year that will also train workers for the oil, gas and mining industries and may start a similar center on the east coast, he said. Keeping resources projects on schedule and budget amid a contest for labor will be a challenge for the industry, he said.

"There’s enormous pressure to get that right," according to Anderson.

GE forecasts sales will rise as much as 25 percent this year in fast-growing regions such as Australia, Latin America and Africa. The company supplies natural gas compression systems, power-generation equipment and wind turbines, among other equipment and services.

Australia’s expansion is being driven by China, the nation’s biggest trading partner, which is buying up iron ore, coal and natural gas as millions of people in the world’s most populous nation move to urban centers.

The boom has sparked a "feeding frenzy" for companies such as GE that provide equipment and services to LNG and mining projects, Peter Strachan, a resources analyst at StockAnalysis in Perth, said.

"There’s going to be a hiatus toward the end of the decade," he said. "But there is certainly three or four years of strong activity. There are plenty of projects going ahead that could keep the momentum rolling."

GE’s energy division is expected to double its workforce in Australia and New Zealand to 1,000 this year from about 500 in 2007, Anderson said.

GE has won more than $1 billion of work to supply equipment and services to the Inpex-led Ichthys LNG project, a $150 million contract for Apache Corp. APA’s Julimar gas project and an agreement to supply gas turbines for Fortescue Metals Group Ltd. (FMG)’s Solomon mine project. Chevron’s Gorgon LNG venture off northwest Australia awarded GE more than $1.1 billion of contracts, GE said in 2010.

A group including GE also received a contract to supply 22 of the company’s wind turbines for the 55-megawatt Mumbida wind farm in Western Australia, GE said last year. The pact marked the first use of GE wind turbines in Australia.

Leighton Holdings subsidiary Thiess has won a $464m (A$450m) contract from Bechtel for site clearing works for the Wheatstone liquefied natural gas project in Western Australia.

Under the terms of the contract, Thiess will be responsible for bulk and final-finish earthworks for the plant, storm water drainage system and access roads around the project.

Theiss managing director Bruce Munro said the contract built on the company's productive and ongoing relationship with Chevron.

"Thiess brings to the sector a proven track record in managing the logistical challenges of these large geographically dispersed projects and we look forward to growing our involvement in the bourgeoning LNG industry both in Western Australia and Queensland," added Munro.

Work is expected to begin onsite in early fourth quarter of 2012 and is expected to be completed in early 2014.

Thiess said it is the fourth contract on the Chevron-operated Wheatstone project.

Bechtel has previously contracted Thiess in joint venture with various international partners to construct the materials offloading facility and LNG and condensate tanks.

The company will also deliver the Wheatstone microtunnel and a construction village and the site preparation and temporary facilities for Chevron on the Gorgon LNG project at Barrow Island.

U.S.-based PMFG, a provider of custom engineered systems and products, has secured a $4m equipment supply contract for a new liquefied natural gas terminal project in Australia.

PMFG chief executive officer Peter Burlage said this is the third order the company has received in Australia.

"This project underscores our strength in successfully managing projects on a global scale together with our regional experience and leadership talent in LNG projects," Burlage.

"We plan to utilize our regional and domestic manufacturing facilities in addition to regional subcontractors and suppliers for various facets of the project."

Technip was awarded by INPEX CORPORATION a flexible pipe supply lump sum contract for the Ichthys gas field, in Australia. INPEX has novated this contract to McDermott as part of the overall subsea umbilical, riser, flowline EPCI contract. The Ichthys LNG project is a Joint Venture between INPEX (76%, the Operator) and Total (24%).

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 889 kilometers Ichthys gas export pipeline will transport production from the offshore central processing facility through a subsea pipeline to the onshore liquefied natural gas (LNG) facility to be located at Blaydin Point, Darwin, Northern Australia. The Ichthys LNG project is expected to produce 8.4 million tonnes of LNG and 1.6 million tonnes of liquefied petroleum gas per annum, along with approximately 100,000 barrels of condensate per day at peak.

The ‘Supply A -- Production & Gas Export Lines’ contract includes:

-- 3 kilometers of technologically advanced smooth bore 10" flexible gas export risers*,

-- 3 kilometers of 12" production risers

Technip’s operating center in Perth, Australia, will execute the contract with the flexible risers being manufactured at Technip’s flexible plant in Le Trait, France. The contract is scheduled to be completed in the first semester of 2015.

A consortium consisting of GE and a CH2M HILL-UGL joint venture has been awarded an order to provide power generation for the Ichthys LNG power station. The order is worth more than US$900 million, GE said.

As part of the deal, JKC Australia LNG awarded a contract worth US$550 million to a 50:50 joint venture between UGL and the EPC firm CH2M HILL to build a combined cycle power plant (CCGT) on site of the Ichthys LNG project.

As part of the agreement, GE will engineer and supply gas turbines, steam turbines and heat recovery steam generators for the $34 billion Ichthys project. GE said its gas and steam turbine technology will "efficiently and reliably" generate electricity for the onshore facility based at Blaydin Point, Darwin, enabling it to produce more than 8 million tons of LNG each year.

GE will supply five GE Frame 6B gas turbines and three SC4 single-flow steam turbines that will provide 500 megawatts of installed power capacity for the facility. Design, procurement and fabrication for the combined cycle power plant works are expected to start immediately, with an on-site commencement in mid-2013 and completion expected by the end of 2016.

John Anderson, senior region executive, Australia and New Zealand at GE Energy, said the company's "extensive track record in providing reliable and efficient gas turbine power plants" underpins its "ability to offer a complete customized solution for power generation on the Ichthys project."

This milestone Ichthys LNG power station project follows on from the successful installation of the Tamar Valley CCGT by UGL in 2009 and the Darling Downs CCGT completed by GE and CH2M HILL in 2010.

Kunlun Energy, the gas distribution arm of China's largest oil and gas producer, PetroChina, saw its share price fall 3.1 per cent April 3 after the concern announced it would raise HK$10.48 billion to fund its liquefied natural gas projects.

PetroChina has agreed to sell 800 million existing shares and subscribe to the same number of new shares to be issued by Kunlun, at HK$13.10 each, 7.6 per cent less than the closing price on April 2. Kunlun shares closed at HK$13.74 April 3.The exercise will raise HK$10.25 billion in net proceeds for Kunlun. PetroChina's stake will be diluted to 58.7 per cent from 65.1 per cent as a result.

The proceeds will become working capital to develop Kunlun's LNG business.

Kunlun said the share placement will allow it to "capture future expansion and acquisition growth opportunities as and when they arise".

Kunlun said in its recent annual results announcement statement that it began the construction of 15 LNG processing plants on the mainland last year, with a total daily capacity of 20 million cubic meters. Four of the plants, in Inner Mongolia, Xinjiang, Qinghai and Hainan,have a combined daily capacity of 1.38 million cubic meters. The rest are slated to come on stream in the next two years.

Kunlun also said it has 23 compressed natural gas (CNG) filling stations and 109 LNG stations under construction. CNG is compressed gas stored on vehicles in high-pressure tanks, while LNG is liquefied by being chilled to minus 163 degrees Celsius, and is moved by special tanks on vessels or trucks.

PetroChina Jiangsu built and operates an LNG terminal in Rudong, Jiangsu province, that re-gasifies LNG imported from Qatar, while PetroChina Dalian built and operates one in the city to import gas from Australia.

Beijing Pipeline operates long-distance gas pipelines connecting gas fields in Shaanxi to markets in Beijing, Tianjin, Hebei, Shandong, Shanxi and Shaanxi provinces.

Kunlun posted a net profit of HK$5.61 billion for last year, up 33.7 per cent from a restated 2010 profit.

Oil and gas production accounted for 43 per cent of before-tax profit of HK$10.4 billion, against 41.6 per cent from pipeline transmission, 12.8 per cent from city gas sales, and 2.5 per cent from LNG terminal processing.

Kunlun had a net debt-to-equity ratio of 52.1 per cent at the end of last year, up from 32.4 per cent a year earlier.

INDIA

India’s state owned GSPC Group promoted Gujarat State Petronet Limited (GSPL) is evaluating a liquefied natural gas (LNG) terminal at Sikka in Jamnagar district on West Coast. The move is aimed at securing supplies for its proposed 4,000 km long cross country natural gas transmission pipeline. GSPL led consortium consisting of oil marketing companies IOC, BPCL and HPCL will have to secure 100 mmscmd of natural gas to operate the proposed pipelines at full capacity.

Over Rs 1,000 crore GSPL is assessing the possibility to commission 5 MMTPA (equivalent to 20 MMSCMD of natural gas) capacity, which can be doubled in coming years. Jamnagar district is also the base of India’s two both private sector petroleum refineries of RIL and Essar that consume sizable quantities of LNG for their process. Currently, RIL operates India's largest all-weather petroleum terminal at Sikka for export and import of crude and petroleum products through single point moorings under the jurisdiction of Gujarat Maritime Board.

On March 30, GSPL invited expressions of interest from consultants to prepare a detailed report and examine the possibility of commissioning the LNG project at Sikka.

BSE listed GSPL and partners are expected to commission Mallavaram-Bhopal-Bhilwara-Vijapur (1585 km), Mehsana-Bhatinda (1670 km) and Bhatinda-Jammu- Srinagar (740 km) pipeline projects in next three years. "GSPL is open to join hands with private players for LNG projects. We have already invited expressions of interest from upcoming LNG projects for equity participation and ensure terminal capacity," said a top government of Gujarat official. He avoided commenting on proposed terminal at Sikka. "It is premature to comment on future plans for Sikka before conducting the feasibility studies," said the official. However, he did not rule out the possibility of joining with private players including RIL and Essar.

Meanwhile, flagship Gujarat State Petroleum Corporation (GSPC) has joined with diversified Adani Group to commission the 5 MMTPA LNG terminal at Mundra in Kutch district. GSPC and Adani are scouting for a strategic partner. They are also open to offering stakes to retail investors.

State-run utility GAIL is working on a makeover plan that will double the capacity of Dabhol power project’s gas import facility to 10 million tonnes a year, said company chairman B C Tripathi after hosting the seventh Asia Gas Partnership Summit at the end of March.

The 2,000 mw Dabhol power project, situated in Ratnagiri district, is operated by an equal joint venture of GAIL and generation utility NTPC. GAIL is in charge of the LNG terminal, while NTPC looks after the generation.

Tripathi said GAIL is looking to tie up about 2 million tonne of LNG for import at the Dabhol LNG terminal. "We are in discussion with suppliers for buying 1-2 million tonne a year of LNG on a short-term contract of up to three years," Tripathi said. "It will all depend on how successful we are in commissioning the terminal".

GAIL has restored the derelict terminal left behind by U.S. major Enron after it went bust and the power project stalled over payback charges. The company is expecting the first gas cargo that will be used to test the facility.

The doubling of the terminal fits into GAIL’s long-term plan. The company has entered LNG trading and taken stakes and tied up gas supplies with U.S. shale gas firms. Doubling the Dabhol LNG capacity would give the company a captive import facility. Combined with its own pipeline network and distribution set-up, the company will have a distinct advantage over rivals.

India is increasing LNG imports after Reliance missed production targets at KG-D6. Dabhol will be the third LNG terminal after Shell’s Hazira facility and Petronet’s Dahej terminal. Petronet LNG plans to start India’s fourth such plant in Kochi in the second half of this year.

Gail (India) Ltd. said Andhra Pradesh Gas Distribution Corporation Ltd., or APGDC, a company jointly promoted by Gail Gas Ltd. and Andhra Pradesh Gas Infrastructure Corporation Pvt. Ltd., or APGIC, had signed a Project Framework Agreement or PFA with GdF Suez LNG UK Ltd. for jointly setting up a Floating Storage and Regasification Unit or FSRU in offshore Andhra Pradesh.

APGDC has been mandated to establish an LNG importation facility on the coast of Andhra Pradesh to narrow the gap between demand and supply position and in the context of restricted availability of gas in the state of Andhra Pradesh and consequential under-utilization of infrastructural especially in the power sector.

To implement the project efficiently and effectively, APGDC selected GdF Suez LNG UK as the strategic partner for conducting a detailed feasibility study and subsequent formation of a Special Purpose Vehicle for developing the FSRU project.

Under the PFA, APGDC and GdF Suez shall jointly conduct a feasibility study and target commissioning of the FSRU project by the end of 2013.

With the commissioning of the FSRU project in Andhra Pradesh, gas consumption in the State would get a boost and the downstream activities are expected to significantly contribute to the State's economic growth.

Pacific Rubiales Energy Corp. acting through its wholly owned subsidiary Pacific Stratus Energy Colombia Corp. ("PSE"), recently announced the signing of a natural gas Liquefaction, Regasification, Storage and Loading Services Agreement with Belgium based Exmar NV ("Exmar").

The Agreement calls for Exmar to build, operate and maintain a Floating Liquefaction Regasification & Storage Unit ("FLRSU") to be located on the Colombian Caribbean coast. The Agreement grants PSE exclusive guaranteed rights to supply and liquefy up to 69.5 MMcf/d over a 15 year period, under a tolling structure. The FLRSU will have a storage capacity of 14,000 m3 (+/- 0.5 million tonnes per annum) of LNG and will be able to accommodate alongside a 140,000 m3 LNG Floating Storage Unit ("FSU"). Commercial Operations of the FLSRU are estimated to start in the fourth quarter of 2014.

Ronald Pantin, Chief Executive Officer of the Company commented: "We are very excited with this Agreement as it opens new markets and fast-tracks monetization of the Company's extensive natural gas reserves. This leverages the Company's strategy to explore and develop its large gas resources in northern Colombia, and also reinforces our view that Colombia has enough gas resources to become a reliable LNG supplier for the region."

As part of the project, PSE will build an 88 km, 18" diameter pipeline from its producing La Creciente Field to the Caribbean coast with an initial design transportation capacity of 100 MMcf/d. Gas for the project will be sourced from La Creciente Field.

With this project, the Company will be initially targeting markets of Central America and the Caribbean, aiming to replace fuel oil and diesel currently used for power generation. The project will also open potential industrial and residential market opportunities for natural gas in these countries, while putting in place new incentives to explore and develop the large undiscovered natural gas resources in Colombia.

DNV has signed a MOU with Korea Gas Corporation (KOGAS), South Korea, to cooperate on research and development in the LNG sector. While this is DNV s second MOU with KOGAS, following the first in 2010 to cooperate on EHSQ issues, DNV is the first international risk management organization in Korea to cooperate with KOGAS on research and development projects in the LNG sector.

DNV and Korea Gas Corporation (KOGAS) agreed to cooperate on research and development in the LNG sector. Based on the signed MOU, DNV and KOGAS will co-organize conferences and cooperate on R&D projects throughout the entire LNG value chain, from upstream to downstream, including gas reservoir exploration, natural gas production, liquefaction, transportation, storage, regasification and supply.

DNV has maintained a good relationship with KOGAS, providing several SHE risk management services that include EHSQ evaluation and safety culture assessment. "We are happy to expand our cooperation to the research area and further our long-term partnership with KOGAS. Based on our expertise in the LNG industry, we anticipate helping KOGAS to acquire innovative technology and strengthen its position in the global market," says Mr Jon Rysst, Regional Manager for DNV Korea and Japan.

As the sole LNG provider in Korea, KOGAS is continuously expanding its investment in foreign resource development projects and acquisitions of non-conventional gas, such as shale gas, to obtain a stable energy source. Furthermore, KOGAS is more focused on the mid-downstream LNG business, which concentrates on a return on investment based on LNG demand and stable income generation through technical services.

While continuously providing SHE risk management services to KOGAS to strengthen its mid-downstream operations, DNVwill further its cooperation with KOGAS in order for this national LNG provider to acquire advanced technical competence and create long-term value in the global LNG market.

Esso Highlands, a subsidiary of International Oil Company (IOC) ExxonMobil Corporation, announced that a dispute with landowners related to the Papua New Guinea (PNG) LNG liquefaction project has ended.

For approximately two weeks the dispute caused disruption to development work at the Hides gas field in the Southern Highlands region, which is being developed to supply a planned 6.6-million-t/y liquefaction facility, northwest of the capital Port Moresby.

According to ExxonMobil spokesperson Rebecca Arnold, "Community leaders in the Hides area have come to a resolution with the government to allow work in Hides to resume. We have begun to mobilize our workforce to recommence work."

However, it remained unclear what sort of agreement was reached with community leaders in the Hides area, who agreed to lift the blockade of the Hides site after it materialized that the government was planning to announce a National State of Emergency to restore law and order. However, PNG's National Executive Council eventually decided on March 28 not to declare the national state of emergency but to deploy troops to the field site to enhance security instead.

The ExxonMobil-led PNG LNG project has experienced periodic disruptions from groups of landowners unhappy with aspects of the Umbrella Benefit-Sharing Agreements, which specified how the state's revenue streams from the project would be distributed.

The current disruption appears to have been triggered by the PDL 7 Hides 4 Landowner Umbrella Association Incorporated group, which is calling for progress on demands made in the Hides 4 ADPL 7 Licence Benefit Sharing Agreement, which reportedly include US$46.52 million (99 million kina) in additional compensation for the project, increased local employment opportunities in the area through making contracts available to local communities, upgrading the Para Health Centre to a referral hospital, and establishing a permanent water supply in the region.

Unfortunately, Esso Highlands is not a signatory to the agreement, which is between the PDL 7 Hides 4 Landowner Umbrella Association Incorporated and the PNG government, so the company has little control over whether landowner demands are met, but has to suffer the consequences if they are not.

Perhaps the resolution between landowners and government involved a commitment by the latter to respect its social and economic commitments.

Going forward, pressure from stakeholders in the PNG LNG project on the PNG government could increase to ensure that commitments made in these agreements are respected, to reduce security risks and setbacks to the project schedule, which was already facing cost pressure due to a strong Australian dollar.

Hamworthy Oil & Gas Systems has secured a contract to supply its innovative LNG regasification technology for the third Höegh LNG Floating Storage and Regasification Unit (FSRU) under construction at Hyundai Heavy Industries.

Working together with Sinopacific Offshore and Engineering (SOE) Wärtsilä Hamworthy will design and supply the system concept whilst the key equipment and fabrication will be supplied by SOE. This partnership agreement follows on from the contract to supply a propane-seawater regasification system for the first two 170,000m3 capacity vessels signed in November last year.

The floating regasification market is experiencing significant uptake and Höegh have projected annual growth in the LNG market of 6-7% over the coming few years. Sveinung Støhle, Höegh LNG’s President and Chief Executive, was quoted as saying: "Our strategy to expand in the floating regasification market worldwide remains firm and we believe in strong continued growth in this segment."

Reidar Strande, LNG Business Unit Director, Hamworthy Oil and Gas Systems said: "This contract for Höegh LNG follows on from the joint project with SOE in supplying our regasification module for the converted Golar Khannur. The module concept was a fast-track project allowing the regasification system to be almost complete before lifting onboard the vessel, with very few interfaces. Delivery of this equipment took place in November 2011."

The Spanish government has passed a legal decree postponing the start up of Spain's seventh liquefied natural gas import terminal. El Musel, at the Spanish port of Gijón, will be put into hibernation in a drive to save money by trimming the country's regulated access tariff bill, under a decree law announced in the Spanish state bulletin BOE on March 31.

The decree acts on a proposal published by Spanish energy regulator CNE early in March in which it said freezing the commissioning of El Musel (construction of which is almost complete) would save around E13m/year in regulated third-party access charges.

"The construction of new gas infrastructure should be limited to keeping to binding international commitments derived from the construction of gas interconnections and serving new consumers, provided this does not entail additional costs to the system," the decree said.

It added that the new measures would not affect security of supply, since usage of existing LNG import infrastructure was currently at only around 40-60% of capacity and would remain so until 2014. Falling gas demand in Spain and higher imports via new pipeline infrastructure are behind the declining use of Spain's LNG terminals. Construction on El Musel will continue but the plant would not be commissioned "until demand justifies it", the decree said.

A spokeswoman for Spanish gas transmission system operator Enagás, which is building the plant, was unable to immediately give a target start-up date and a government spokesman could not be reached for comment.

The government's decision postpones not just El Musel but also all gas infrastructure projects classified as "Category R". These are projects reclassified from mandatory projects to being subject to possible reconsideration on financial grounds, in the 2012-2020 Infrastructure Plan. The only exclusions to this are planned upgrades to the six existing LNG terminals.

The blanket nature of the postponement of all Category R" projects means that several associated pipeline links related to El Musel have also been shelved. These include links between El Musel and the main grid. Enagás has already spent E380m on El Musel alone. The Enagás spokeswoman admitted that the decision was frustrating, but was unable to say whether the company would appeal against the decision, or when it might finally be commissioned.

An appeal seems unlikely since, according to both the CNE and the government, the new LNG terminal would jeopardize the safe operation of the existing plants - three of which are owned by Enagás - by dangerously reducing LNG inflows.

Import terminals require a minimum level of LNG to pass through them or they have to be taken off line. This is understood to be a reference in particular to the independently operated Mugardos LNG terminal just down the coast from Gijón at Ferrol. According to Enagás, the terminal unloaded 14% less LNG in February than in the same month last year, with only three vessels docking at the terminal.

A new gas-fired combined heat and power (CHP) plant could be on the horizon for the Milford Haven waterway, South Hook LNG has confirmed. The news comes after the UK Government announced its backing for a major expansion in gas generated electricity to avert a looming gap in power generation capacity.

"The shareholders of South Hook LNG are investigating the potential of a new gas-fired combined heat and power facility at the South Hook site," a South Hook LNG Terminal spokeswoman confirmed. "Reviews are at an early stage," she said, declining to elaborate further.

South Hook LNG terminal, located in south Wales, is one of Europe's biggest LNG import terminals. It can supply up to 20% of the UK's gas demand.

The owners of South Hook LNG - Qatar Petroleum, ExxonMobil and Total – built the regasification terminal primarily to take cargoes from their joint production in Qatar

Gazprom may abandon plans to pipe Arctic gas from its Shtokman project, a top executive said, potentially giving Russia's top energy firm more leeway to sell supplies from the huge field to customers outside Europe.

Gazprom may instead focus on producing more easily transportable liquefied natural gas at the Barents Sea deposit, deputy chief executive Alexander Medvedev said - the first time the company has mentioned that option. The comment is likely to stoke concerns in Europe about whether Russia can be relied on as a major long-term gas supplier, given rising demand for the fuel in Asian markets.

European companies have complained that Gazprom - which supplies a quarter of the continent's gas needs - has not met their requests for extra deliveries during the current cold snap. Gazprom said it has been unable to meet all the additional demand.

Prime Minister Vladimir Putin, who will serve a third term as president from May, said last month that Russia should wean itself off its dependency on European pipeline gas deliveries and expand into super-cooled LNG, which can be delivered to the markets of Europe, the Middle East and Asia by tanker without infrastructure constraints.

Speaking to reporters at the launch of a new gas well in Urengoi in the Arctic region, Medvedev admitted the company's exports to Europe might be less than the 154 billion cubic meters (bcm) it has projected.

"We said that exports will total 154 (bcm this year) but even if it is 150 bcm, revenues won't be lower," he said. Earlier a Gazprom's official said the company will increase its gas production next winter. Shtokman's gas reserves are estimated at 3.9 trillion cubic meters (tcm), enough to meet a year's global consumption and making it potentially the world's tenth largest field. In theory, gas from the field is due to be piped to Europe via the Nord Stream pipeline - launched last November - from 2016 and shipped as more costly liquefied natural gas from 2017.

But its development has been fraught with problems and last month its operating consortium deferred for the third time since March 2011 a final decision on whether to press ahead with initial investments of around $30 billion.

Russia's two biggest natural gas producers, Gazprom and NOVATEK, have signed a memorandum of cooperation, in compliance with which the two companies consider the possibilities for the creation of joint ventures to raise the capacity of the facilities for the production of liquefied natural gas on the Yamal Peninsula and joint development of resources at the Gydan Peninsula, the Gazprom Information Department said in a statement on April 17.

In order to increase LNG production on the Yamal Peninsula, Gazprom and NOVATEK will consider the possibility to set up a joint venture in the Tambeyskaya group of deposits, which belongs of the Russian gas state monopoly. Under the initial plans, Gazprom will hold a 75-percent stake, while NOVATEK will get a 25 percent stake in the project, the Information Department of the Russian major natural gas producer said.

While aiming at the development of resources located at the Gydan Peninsula, the two gas producers plan to set up a joint venture on the basis of NOVATEK's Utrenneye (Salmanovskoye) field, the Information Department said. Gazprom and NOVATEK will hold equal shares in the project.

Both companies will do their utmost to draft and adopt a unified comprehensive program for the development of Gydan fields belonging to Gazprom and NOVATEK, the Information Department said. The Yamal LNG production is not subject to the Shtokman LNG project's commissioning deadlines.

The North Tambeyskoye, the West Tambeyskoye and the Tasiyskoye gas fields fall into the Tambeyskaya group of deposits of the Yamal Peninsula and located in a close proximity to the creating infrastructure of the South Tambeyskoye field and Sabetta port, the Information Department said.

Reserves of natural gas of the ABC1+C2 category at the above-mentioned fields are estimated at 1.56 trillion cubic metres, the Gazprom Information Department said. The aforesaid reserves can ensure LNG production of about 20 million tonnes a year.

The Utrenneye (Salmanovskoye) field is located on the Gydan Peninsula. Its reserves of natural gas of the ABC1+C2 category are estimated at 767.1 billion cubic meters, the Information Department said.

NOVATEK is Russia's largest independent natural gas producer, and the second-largest in overall production after Russia's gas giant Gazprom. The company is based in the Yamal-Nenets Autonomous Area and maintains its sales office in Moscow.

Partners in the huge Leviathan natural gas field offshore Israel aim to sell stakes in the field to bring in other stakeholders and raise cash to help develop the project, sources close to the matter said. The consortium, led by Houston-based Noble Energy and Israel's Delek Group, have hired Citigroup to bring in one or more new partners, the sources said.

The Leviathan gas field is located 80 miles (130 km) off the Mediterranean port of Haifa and has estimated gas reserves of 17 trillion cubic feet (tcf), enough to cover Israel's gas needs for generations and make it into an exporter of liquefied natural gas.

"The partnership is seeking to bring in a partner who has LNG development and marketing skills," said one source, adding that members of the consortium would sell down their stakes to the new partner in order to raise cash for the field's development as well as further exploration in the eastern Mediterranean. Another source close to the matter said that likely partners could include European utilities with upstream gas interests or Russia's Gazprom.

"We know that Gazprom has been talking about asset stakes, and also Spain's Gas Natural, but GDF Suez is also interested," the source said, adding that the French company would be the most economically sound option.

"GDF Suez has sufficient LNG experience, big marketing and client potential, as well as assets in neighboring Egypt, which already has a pipeline connection with Israel," although the Egypt-Israel gas pipeline is not currently a major factor in the decision-making, because it has been blown up several times in the past year, the source said. Russia's Gazprom has so far relied largely on piping its gas to Europe but now wants to expand its LNG business in Asia. Israel's gas fields, situated close to the Suez Canal, would be well suited for this, the sources said.

They said that Asian utilities are also interested in new LNG assets but that a deal with Israel would be politically sensitive with existing clients in the Middle East and Southeast Asia.

The sources requested anonymity because they are not authorized to speak to media on specific deals. Citigroup and officials of the consortium were not immediately available for comment.

Noble owns 39.66 percent of Leviathan, while Delek Energy subsidiaries Avner Oil and Delek Drilling each own 22.67 percent. Ratio Oil owns the remaining 15 percent.

Lebanon's ministry of energy and water has invited eligible companies involved in the liquefied natural gas import and re-gasification industries to express their interest in a planned local project, the state-run National News Agency reported April 5.

The project includes operating a floating plant for LNG re-gasification starting from early 2015 and setting up an offshore floating terminal for receiving LNG vessels, the ministry said, according to the news agency.

Interested companies should apply before the June 4 deadline, it added.

Lebanon, which plans to explore for oil and gas, is suffering from severe power shortages. Its existing electricity generating plants, which are mainly fired by costly and polluting fuels, can't meet the country's growing demand for energy.