Cheniere Energy Inc.'s proposal to build an LNG export terminal in Corpus Christi, Texas, met an almost entirely warm reception at a FERC open house.

Cheniere spokesman Andrew Ware said February 29 that the vast majority of responses from the 127 people who attended the February 28 meeting in Portland, Texas, were positive.

"They want to have the jobs and the taxes associated with the project," Ware said. "We've been in the Corpus Christi area for a long time, going back to when we were going to build an import terminal. They were very supportive of that project."

"We've had land down there," he added. "We've already spent a significant amount of money to prep it for construction."

FERC officials were present, but the FERC Media Relations Division noted that the project is under review and declined to provide the commission's view of the meeting.

Cheniere announced its plans for the Corpus Christi liquefaction project on December 16, 2011. It is the second such project the company plans to put on the Gulf of Mexico, following its Sabine Pass liquefaction project in Louisiana. The Corpus Christi project is in the pre-filing process, and Ware said Cheniere still expects to file a formal application this summer.

Ware said Cheniere has not begun the formal marketing process for the Corpus Christi project, but company officials know customers are out there. "There is certainly demand out there to support it," he said. "We're fully subscribed for Sabine at this point from the four main customers we have. And from our discussions, we know that there's more demand in the market."

The Corpus Christi terminal would provide an additional 13.5 million tonnes of liquefaction capacity in the Gulf of Mexico per year. The site sits relatively close to the natural gas supply in the Eagle Ford Shale in south Texas.

GE and Chesapeake Energy Corporation on March 7 announced a collaboration to develop infrastructure solutions that will help accelerate the adoption of natural gas as a transportation fuel. This groundbreaking technology and services project marks a significant milestone toward increasing energy independence in the United States through the increased use of natural gas--an abundant, reliable and cleaner-burning source of energy for both consumers and commercial users.

To formalize the agreement, GE and Chesapeake have signed a memorandum of understanding on a product and services development partnership, representing a multi-year collaboration between the two companies to develop and bring to market compressed natural gas and liquefied natural gas transportation and natural gas home-fueling solutions. By improving access to CNG, which is most commonly used in light- to medium-duty vehicles such as pickups, vans, SUVs, taxicabs, transit buses, refuse and delivery trucks as well as consumer vehicles, along with LNG, which is commonly used for heavy-duty industrial purposes, dependence on foreign energy sources can be reduced while simultaneously lowering fueling costs and vehicle emissions.

The collaboration is designed to leverage GE's global Oil & Gas technology portfolio with Chesapeake's expertise in developing innovative fueling solutions to lower the ownership and operational costs of natural gas vehicle (NGV) fueling stations. With the development of shale resources dramatically increasing the amount of low-cost natural gas in North America, the GE-Chesapeake collaboration can help incentivize operators to put more NGVs on the nation's highways.

As part of the March 7 announced collaboration, beginning in the fall of 2012 GE will provide more than 250 modular and standardized CNG compression stations for NGV infrastructure. These units, also known as "CNG In A Box™," have gone through GE's rigorous eco-imagination-qualification process and will provide the core infrastructure to enable expanded access to CNG at fueling stations and other designated installations.

A vehicle using CNG can reduce annual fuel costs up to 40 percent, assuming 25,700 miles per year driven, gasoline priced at $3.50/gallon and CNG at $2.09/gasoline gallon equivalent. This represents savings totaling as much as $1,500 per fleet vehicle per year. In total, for each fleet vehicle using fuel provided by CNG In A Box instead of gasoline, a fleet operator can reduce CO2e emissions from fuel combustion by about 24 percent, or 2.2 metric tons per vehicle annually, assuming an average fleet vehicle travels approximately 25,700 miles per year.

"Both GE and Chesapeake are known for taking on tough energy challenges and putting the best minds and technologies to work to develop solutions," said Aubrey K. McClendon, Chesapeake's Chief Executive Officer. "The partnership announced today between GE and Chesapeake's affiliate, Peake Fuel Solutions, combines Chesapeake's natural gas expertise with GE's extensive global manufacturing capabilities and will bring transformative products to industries and individual consumers across the U.S. These products and services will allow customers to enjoy the clear advantages of clean, affordable and abundant American natural gas at about half the cost of gasoline."

Said GE Energy President & CEO John Krenicki, "GE is fundamentally committed to natural gas—our technologies help extract it, move it and turn it into power, whether it's highly efficient gas turbines delivering electricity at the utility scale or, in the near future, a vehicle at a refueling station. What makes this project particularly exciting is that it paves the way to taking the immense reserves of natural gas being discovered in the U.S. and using them right here in the U.S. That paves the way for faster economic growth, energy security, more jobs and reduced environmental impact."

This CNG technology will be brought to market by Peake Fuel Solutions--a Chesapeake affiliate--which has extensive experience with natural gas vehicles, vehicle emission controls and natural gas market dynamics. Chesapeake also brings considerable in-house expertise in CNG market development to the GE collaboration, including retail station relationships, fleet outreach and education programs and policy engagement.

CNG In A Box takes natural gas from a pipeline and compresses it on-site at an industrial location or at a traditional automotive refilling station to then turn it into CNG. A CNG vehicle, such as a taxi, bus or small truck, can then refill its tank using a traditional fuel dispenser, much like those used for diesel or gasoline refueling.

Key features include:

•The gas compression, storage, cooling, drying and controls are easy to ship and maintain due to its compact "In Box" design.

•The units come in two configurations: an 8 foot x 20 foot container or 8 foot x 40 foot container, depending on the site's need.

•Its modular and intuitive design makes it "Plug & Play" on-site.

•The offering includes GE Wayne branded dispensers with credit card capability and provision for "Point Of Sale" interface.

•The fuel dispenses at a rate of about 7 gasoline gallon equivalent per minute.

Other elements of the new collaboration include:

•Aftermarket services for natural gas fueling infrastructure.

•GE's LNG fueling plants, which adapt GE's proven large-scale LNG liquefaction technologies to smaller-scale operations. Using LNG as a substitute for diesel or fuel oil can reduce combustion emissions up to 25 percent.

•Development of home refueling technologies.

•Co-marketing of products and services resulting from the partnership.

ExxonMobil says North American producers will struggle to tap lucrative Asian export markets for their shale gas deposits, arguing current low prices will instead spur greater domestic consumption for the unconventional fuel.

Rob Gardner, chief economist at the world's largest energy company, told The Australian Financial Review that expectations of the U.S. becoming a major LNG exporter in the next few years were unrealistic.

"It's really early days for North America to talk about LNG exports," Mr Gardner said. "I think there's limited confirmed project approvals for [LNG] export and until that opens up, you're not going to see a lot on that front."

The massive spike in production in recent years has led to a surplus in domestic inventories, slashing the price of Henry Hub natural gas near a 30-month low February 29 at $US2.44 per million British thermal units.

Major LNG importers including South Korea and Japan typically pay up to $US12 per million BTU for long-term gas contracts, offering a significant premium to domestic U.S. deals.

Exxon was one of the earliest major oil and gas companies to place a bet on shale when it paid $US41 billion to buy U.S. company XTO Energy in 2009. XTO has one of the largest unconventional gas land holdings.

Mr Gardner's views echo comments made earlier this month by Exxon's former chief executive, Lee Raymond, who said there was likely to be a big debate in the U.S. over whether to allow large-scale LNG exports given local demand for the clean-burning fuel. Mr Gardner said it would be "wild speculation" to predict how the market for U.S. shale gas would develop in terms of exports. But he argued local utilities would take advantage of the current supply glut to increase their exposure to gas.

"Gas we think is going to penetrate more heavily into power generation both as a result of the availability of gas and the increased impact of fuel mix effects from carbon policies."

UBS estimates shale gas will make up half the U.S. gas market - the world's largest - by 2030, particularly given the commitments of major energy and resource companies to the sector with robust balance sheets.

Private equity player Blackstone in March committed $US2 billion to help fund the construction of Cheniere Energy's LNG plant in Sabine Pass, Louisiana, while Australia's Macquarie Group is backing a similar export project at Freeport LNG along the US Gulf Coast.

FERC has vacated Crown Landing LLC's authorization to build an LNG import terminal on the Delaware River in southern New Jersey and vacated Texas Eastern Transmission LP's authorization to build an associated pipeline.

"On January 6, 2012, Crown Landing filed a letter with the commission stating that it has elected to terminate its proposed project and requesting that the commission revoke the authorizations issued to Crown Landing," FERC said in the February 23 order. "Since Texas Eastern did not construct and place the associated pipeline facilities into service by June 20, 2010, as required, its authorization has expired. Therefore, we are vacating Crown Landing's and Texas Eastern's authorizations to construct the proposed LNG facility and associated pipeline, respectively."

In its January 6 request, Crown Landing had said it was surrendering its authorization for the project or, if the agency preferred, asking the commission to revoke it.

Crown Landing cited major changes in the U.S. gas industry and the global market as the reasons behind its decision. "During the past two years the combination of the significant increase in natural gas production from North American shale resources which has resulted in lower prices, and the growth in demand for LNG in the rest of the world make it unlikely the company can secure supplies of LNG on economic terms attractive enough to ensure the sustained profitability of the project at the proposed site," Crown Landing President and CEO Gordon Shearer wrote FERC.

In June 2006, FERC authorized Crown Landing to build and operate an LNG terminal in Gloucester County, N.J., and authorized Texas Eastern to build and operate the terminal's takeaway pipeline. The order required the companies to make their facilities available for service by June 2009. Crown Landing applied for an amendment to the original design and obtained three extensions, the last one ending June 30 of this year.

Hess LNG LLC, a unit of Hess Corp., took over Crown Landing from BP America Inc. in 2009. Texas Eastern is a subsidiary of Spectra Energy Corp.

The company that wanted to build the Broadwater floating liquefied natural gas terminal in the center of Long Island Sound has formally asked to withdraw its Federal Energy Regulatory Commission certificates, opponents of the project said.

New Haven-based Save the Sound and state Rep. Lonnie Reed, D- Branford, in a prepared statement both hailed the move as a sign the plan of Broadwater Pipeline LLC is history.

"In sending a letter ... requesting to vacate their certificates, Broadwater has signaled that (the) proposed floating gas plant is finally dead," said Leah Schmalz, director of legal and legislative affairs for Save the Sound, a program of the Connecticut Fund for the Environment.

"Eight years ago, the citizens of Connecticut and New York recognized that this proposed project was not good for our environment or our livelihood," Schmalz said.

Reed, who organized the first interstate rally opposing Broadwater, said "total withdrawal of Broadwater may seem anti- climactic, but to me, this is a powerful reminder of all we accomplished by working together on both sides of the Sound."

She called it "a moment to remember and a model for future cooperation."

For most people, Broadwater died in April 2009, when the U.S. Department of Commerce upheld the state of New York's rejection of required permits. Broadwater would have been a 1,200-foot-long floating platform in the middle of the Sound.

But Broadwater had kept its federal permissions until now.

Broadwater will not pursue any aspect of the project, Broadwater attorney Kenneth Wiseman said in a letter to FERC, according to The Day of New London.

Broadwater would have posed a number of threats to the environment and the economies of New York and Connecticut, opponents say.

In addition to being nearly four football fields long, it would have risen 20 stories and been surrounded by an armed security zone opponents said would have disrupted commercial fishing and recreational boating.

BP PLC, ConocoPhillips and Exxon Mobil Corp. are in talks on a $40 billion project to ship liquefied natural gas from Alaska to Asia, the Financial Times reported March 21.

The companies and Alaska officials hoped to resolve a lease dispute at the Point Thomson oil and gas field in the coming week, the FT said, citing people close to the negotiations.

Alaska Gov. Sean Parnell told the newspaper he is "cautiously optimistic" about the plans.

Foster Wheeler AG announced March 12 that a subsidiary of its Global Engineering and Construction Group has been awarded the basic design and front-end engineering design contract by Complejo GNL del Este, a Consortium formed by Dominican and Colombian companies that participate in the energy sector of these countries, for a new LNG receiving terminal and jetty to be built in San Pedro de Marcoris in the Dominican Republic.

The Foster Wheeler contract value for this project was not disclosed and will be included in the company's first-quarter 2012 results.

Foster Wheeler has previously completed a feasibility study for the selection of the most suitable technology for the new terminal, which will be designed for a send-out capacity of 240 million standard cubic feet per day (MMscf/d), with an LNG storage tank of 160,000 cubic meters. The design will also consider future expansion(s) up to 700 MMscf/d. Foster Wheeler will work with a local partner in executing this work, which is expected to be completed in September 2012.

"We are pleased to receive this award, which demonstrates our client's satisfaction with the feasibility study we have completed and Complejo GNL del Este's confidence in our LNG expertise and ability to deliver fast-track execution strategies," said Umberto della Sala, President and Chief Operating Officer, Foster Wheeler AG. "Latin America is a strategically important region for Foster Wheeler, and is a region where we already have a very strong track record in winning and successfully executing large, complex projects."

The government of the twin-island nation of Trinidad and Tobago in the 1990s, moved forward with construction of liquefied natural gas export facilities, the first in the Latin America and Caribbean region. With its prime location in the Caribbean, Trinidad’s LNG exports, through four trains with a combined processing capacity of 18.6Mt/y, were destined primarily for the U.S. which due to its lack of gas reserves at home coupled with its growing appetite for gas and relatively high gas prices, was a natural market for Trinidad’s exports.

The U.S. gas market has changed in recent years due primarily to issues related to slow economic growth and the boom in shale gas production. While the former issue has somewhat affected gas prices, the latter has affected internal demand for gas, directly impacting U.S. demand for imports of LNG from Trinidad. The trend does not look to reverse itself anytime soon, and so the Trinidad government has already begun to divert its LNG exports to other markets to make up for lost market share. While this move appeared to be the only one the government needed to make to guarantee future LNG export revenues, an apparent unstoppable decline in gas reserves continues to overshadow moves into new LNG markets: all could be in vain without discovery and development of new gas reserves.

After reaching a peak in 1999, Trinidad’s proved gas reserves have been in gradual decline, while production continues to increase to fulfill demand in the local market and to supply the nation’s four LNG trains. As a result, Trinidad’s reserve-to-production ratio, an indicator of longevity of actual reserves based on current production, has declined more than fourfold.

At end-1999, Trinidad’s gas reserves peaked at 21.4Tf3 (605Bm3) while production was 0.4Tf3, resulting in a reserves-to-production ratio of 51.6 years. By end-2000, these gas reserves had declined to 19.7Tf3 while production increased slightly to 0.5Tf3, resulting in a reserves-to-production ratio of 38.4 years. However, by end-2010 these reserves had dwindled further to 13.5Tf3 while production increased to 1.5Tf3, resulting in reserves-to-production ratio of just 9.1 years.

Despite declining proved reserves, Trinidad has additional reserve potential in its probable and possible categories, which totaled 7.6Tf3 and 6.0Tf3, respectively, at end-2010. Furthermore, should exploration activities move forward offshore Trinidad where reserve potential is said to be around 26Tf3 on the low end, the country believes there are sufficient reserves to provide the nation with more than twice its existing proved gas reserve base.

Approximately 40% of Trinidad’s gas production is destined to supply the domestic market, including methanol and ammonia plants, while the remaining 60% is destined for export markets in the form of LNG.

Trinidad initiated LNG exports in 1999 and by 2005 some 89% of these exports were destined for the U.S. with the remaining 11% for other markets. Today, just 19% of Trinidad’s LNG exports are shipped to the U.S., with the remaining 81% destined for markets in Europe, Asia and South America. Despite the changes in the end-market for Trinidad’s LNG exports, export revenues have not declined due to higher realized gas prices in the new markets as compared to the U.S. market.

Mild winters, slow economic growth, and additional shale gas production have pushed down benchmark Henry Hub gas prices in the U.S. to less than US$3/MBTU in 2012 from an average of US$3.99/MBTU in 2011. In contrast, gas prices in other worldwide markets have been much higher and remain that way today.

For example, in Europe, where gas prices are linked to fuel oil and gas oil, gas prices at the region’s two main benchmarks, the National Balancing Point and Belgium, were between US$8/MBTU and US$10/MBTU. In Asia, where gas prices are linked to oil prices, the average price of the Japanese Crude Cocktail benchmark was US$13.50/MBTU. In South America, where gas prices are linked to oil prices, gas prices in Argentina and Chile are nearly US$11/MBTU and US$14/MBTU, respectively.

Since initiating LNG exports in 1999, Trinidad's government has grown accustomed to steady LNG export revenue. However, economic slowdown in the U.S. coupled with increased shale gas production has allowed the U.S. to slowly wean itself off foreign gas, primarily from Trinidad. Years of successive Trinidadian governments have neglected to offer attractive taxation and fiscal terms to oil and gas companies interested in exploration activities offshore, causing gas reserves to decline to the high single digits.

In order for Trinidad to continue as a reliable LNG exporter to world markets, the government must now pressure companies to replace a minimum 100% of production and increase field activities to prove up current probable and possible reserves. Furthermore, the government must urgently encourage exploration offshore where large gas reserve potential is in abundance. Failure to advance on any of the these fronts could cause Trinidad to lose LNG market share or worse see the nation lose its potential to export LNG due to its inability to develop and commercialize its abundant non-proved gas reserves offshore.

2. ASIA

Although shale gas may have revolutionized the U.S. energy market, Chevron is counting on it not having the same effect in Asia, for a while at least.

Chevron is investing a planned $39bn in Gorgon and Wheatstone gas projects off the coast of Western Australia to produce liquefied natural gas for Asian markets.

Bringing these two massive projects into service on time and on budget will be a challenge. But Chevron expects that the projects will be lucrative, enabling it to sell gas in Asian markets at high prices for decades.

But now the competition to supply those markets is increasing and the recent discoveries off the coasts of Tanzania and Mozambique are revealing large new resources that will ultimately be sold in Asia. There is also the threat of growing production of shale gas, extracted using the techniques of horizontal drilling and hydraulic fracturing that have created a U.S. production boom.

Shale needs to be considered by anyone wanting to sell gas to Asia, both because it is turning the U.S. into an LNG exporter – the country’s first contract was signed by Cheniere Energy Partners in the U.S. and the UK’s BG Group last year – and because the methods that have proved so successful in the U.S. could be deployed to raise gas production in other countries, particularly China.

The incentive for Asian buyers to seek alternative gas supplies is stronger than ever.

As well as trying to negotiate better gas deals, Japanese companies are also investing in alternative sources of supply.

In February Mitsubishi Corp agreed to invest C$2.9bn for a 40 per cent stake in a gas development owned by Canada’s Encana. The project, in the Montney region of British Columbia, has recoverable reserves estimated at 35tn cubic feet, enough to meet Japan’s needs for nine years.

Mitsubishi plans to liquefy the gas at a plant to be built on the coast of British Columbia, and to begin shipments to Japan and other parts of Asia from 2018.

The company noted that the distance between the coast of western Canada and the Japanese port of Chiba is 7,104km – not significantly longer than the trip from Australia’s north-west shelf (6,938km).

Since the 1970s Japan has bought most of its LNG under long-term contracts linked to the price of oil, and other Asian buyers have followed suit. With Brent crude above $120 a barrel, the benchmark Asian spot market price of LNG is about $15.50 per million British thermal units, about 50 per cent higher than a year ago, according to Platts, and Japanese buyers are typically paying $16-$17 per mBtu.

At the same time, the shale gas glut in the U.S. has sent the benchmark Henry Hub price down to below $2.30 per mBtu, less than a quarter of its peak four years ago. At that level, say analysts, LNG could be imported from the U.S. to Japan at about $9 per mBtu, including liquefaction, transport and insurance costs.

Asian buyers are already moving to take advantage of the cheaper gas. In December GAIL, the state-owned Indian company, became the first Asian buyer of U.S. LNG at prices linked to Henry Hub, after agreeing to buy 3.5m tons a year from Cheniere. Korea Gas Corp agreed a similar two-decade deal in January.

Japanese companies are accelerating efforts to secure cheaper gas in the wake of the Fukushima nuclear crisis.

The shutdown of all but two of Japan’s 54 commercial nuclear reactors after the earthquake and tsunami a year ago means the country has had no choice but to increase imports of LNG, which were up more than a quarter during the ten months to January compared to the equivalent period a year ago, according to Nomura.

Those imports have pushed Japan’s trade balance into the red. The country has posted big trade deficits in seven of the ten months since Fukushima, including a record Y1.48tn deficit in January. The Japanese government is worried about the effect that high energy costs will have on the competitiveness of the country’s manufacturers, particularly when U.S. industry is enjoying the benefits of cheap gas.

Mitsubishi Corp is one of several big Japanese LNG importers applying pressure on producers to change the way long-term supply contracts are drawn up, seeking to weaken the link to oil. Recently an executive at Tokyo Gas told the Nikkei newspaper that the Korea Gas contract with Cheniere would "have an impact on existing LNG transactions".

There is a possible precedent in Europe, where the flow of cheap LNG has encouraged several utilities to take a tougher line with Gazprom, the Russian gas export monopoly, to secure lower prices and move away from oil-linked contracts for some of their purchasing.

However, George Kirkland, Chevron’s vice-chairman and head of its production and gas businesses, expects the oil price link will survive in Asia.

"Europe has a diversified supply. It has Russian gas, it has North Sea gas, it has North Africa gas, and it has LNG. So you’ve got all those playing off each other," he says.

"Asia just doesn’t have the same situation. Japan and South Korea really don’t have any domestic supplies; they don’t have easy pipeline access. So their choice is really an energy alternative … and that’s oil. So it fits there."

It will be important for Chevron that he’s right. The start-up of Gorgon and Wheatstone will shift the proportions of oil and gas in the group’s production from 70/30 to 60/40. However, it expects that oil-linked gas contracts will keep the share of production that earns higher oil-linked revenues at 80 per cent.

Chevron has already sold 70 per cent of its production from Gorgon and 60 per cent from Wheatstone, mostly to Japanese utilities, on contracts lasting 15 to 25 years.

The remainder will be sold into a growing market. LNG demand in the Asia-Pacific region is rising at 20 per cent a year, according to Bernstein Research.

Meanwhile, the alternative sources of supply all face challenges, Mr Kirkland argues. There is already a political backlash growing in the U.S. against LNG exports, based on arguments that the gas should be kept at home for the benefit of American consumers. While China may eventually develop its own shale reserves, he adds, it is unlikely to do so quickly, not least because it lacks the pipeline infrastructure needed to bring the gas to market.

He adds: "You’ve got to believe, with the growth you have in China, every kind of energy you can deliver to the market is going to be consumed."

Analysts generally agree with him. Frank Harris of Wood Mackenzie says he expects most Asian LNG gas contracts to remain linked to oil, partly because there is no viable alternative benchmark.

However, the shale revolution has taken experts by surprise in the past. Less than five years ago, in the summer of 2007, the U.S. government’s advisory National Petroleum Council was talking about "significant expansions in U.S. and North American imports [of LNG] over the next few years." The energy industry is in an era of disruption, with no clear vision yet of winners and losers.

Soaring demand for liquefied natural gas in Asia is driving major new investments into exploration and infrastructure capabilities, according to a consensus at a recent industry roundtable there.

The participants agreed that this would stimulate growth in the region’s rapidly expanding offshore and marine sector as new developments would require additional offshore assets and support services from regional players.

"Furthermore, due to the synergies between Asia’s gas reserves and ship-design capabilities, the region could pioneer a long-term move towards more LNG utilization to reduce vessel emissions and fuel bills of the offshore support vessels," they said.

However, seizing these growth opportunities and moving towards gas-powered vessels of the future, would require multi-party collaborations between energy companies, vessel operators, shipyards, technology providers, marine fuel suppliers and governments to realize the mutual benefits, they said.

The roundtable, hosted by Seatrade, aimed to identify the major growth-drivers and opportunities of the sector in Singapore and around the region. The participants comprised experts from across Asia’s offshore marine industry.

The event was a curtain-raiser to the first Seatrade Offshore Marine Asia conference and exhibition that will take place between April 25 and 27, 2012 to compliment the Singapore Maritime Week.

Seatrade is a leader in maritime and cruise publications, conferences and exhibitions, training, awards and other special projects.

One of the participants, Capt Michael Meade, chief executive officer, M3 Marine Group Pte Ltd, said replacing conventional shipping fuel with LNG could hold the key to a cost-effective and environmentally-efficient industry and Asian operators were looking to lead the way.

"The LNG offers significant benefits over traditional fossil fuels -- cost-efficient to transport over long distances by seas and a clean-burning fuel.

"It will also reduce emissions," he said.

Federal Environment Minister Tony Burke said he supports a UN inspection of the Great Barrier Reef because he wants them to see what he saw when approving a development in the region.

A delegation from the UN's environmental arm UNESCO and the International Union for Conservation of Nature will arrive in Australia in early March to compile a report on the state of conservation within the reef.

The visit was prompted by UNESCO expressing its "extreme concern" over the Queensland and federal governments' approval of a liquefied natural gas plant at Curtis Island.

Mr Burke was not impressed when development was first proposed at Curtis Island.

"I was very hostile to it," he told ABC radio on March 6.

"I want them (UNESCO) to see what I saw."

The part of Curtis Island where the proposed development was located was effectively the northern side of Gladstone Harbor, Mr Burke said.

That's a working industrial port which already has a coal loader and an aluminium smelter among its infrastructure.

"It's very different to the areas that you'd associate with the pristine nature of the Great Barrier Reef," Mr Burke said.

While there were many places along the Queensland coast that had high world heritage values, it was harder to make that argument about places that already had industrial development, such as Gladstone Harbor.

The question for sustainable development was whether it was better to have very small developments up and down the coast in a large number of places or larger developments at a small number of spots, Mr Burke said.

Environmental groups have called the inspection "embarrassing" and a poor reflection on Australia's environmental protection standards.

The delegation will present its report later this year to the World Heritage Committee, which will determine whether to classify the reef as a World Heritage Site in danger.

The parent company of Hayward Baker Inc., Keller Group plc, an international ground engineering specialist with several U.S. operating companies, has secured a key contract with Bechtel Australia Pty Ltd worth in excess of $180 million. The contract is for the piling installation for the Chevron-operated, $30 billion Wheatstone LNG Plant located near Onslow, Western Australia.

The Wheatstone project involves the construction of two liquefied natural gas trains plus a domestic gas plant located approximately seven miles west of the coastal town of Onslow. Gas will be transported via a pipeline from an offshore processing platform located approximately 140 miles off the coast to the onshore facilities.

Oil and gas explorer INPEX has awarded a $5 million contract to IT services firm Empired to implement and manage a project information system for the Ichthys liquefied natural gas project off Western Australia.

Ichthys is a US$34 billion LNG project that received financial go-ahead in January this year.

Empired will implement Coreworx software at INPEX under the first phase of a project codenamed Ichthys Project Information Management (IPIM).

Separately, INPEX also awarded a contract for cost control software to U.S. vendor Skire last month.

The software, also for the Icthys project, was chosen because it can integrate with SAP, INPEX's enterprise resource planning system.

The cost control work is being handled by Skire and its distributor Intergraph.

Japan's Inpex Corp said march 16 it had agreed to acquire a 17.5% interest in the Prelude gas project in Australia from Anglo-Dutch oil major Royal Dutch Shell.

Japan's biggest oil and gas explorer did not disclose the price of the stake in the world's first project for the production of a liquefied natural gas on a floating facility.

This transaction is subject to certain regulatory approvals, including that of the Australian government.

The Prelude project is located off the coast of Western Australia and its LNG production is estimated to reach at least 3.6 million tonnes per annum upon becoming operational after several years. The commissioning is expected around 10 years after the Prelude gas field discovery in early 2007.

Australian contractor, John Holland said on March 14 that its 50:50 joint venture with Aussie compatriot Macmahon Holdings has won a AUD 340 million contract for undertaking site development work for the onshore facilities of the Ichthys LNG Project near Darwin in Northern Australia.

The Macmahon John Holland Joint Venture will undertake civil construction works associated with delivering the finished earthwork levels for the LNG plant and associated facilities, John Holland said.

The works include access roads, earthworks, drainage and ground improvement works required for the establishment of the landmark project, John Holland added.

John Holland Group Managing Director, Glenn Palin, said: "Today's award reflects the diversity of John Holland and our ability to deliver a vast range of works across the energy and resources sector, from site preparation through to design, delivery and commissioning works" .

"The contract builds on our strategy of aligning closely with major EPC contractors on approved projects in the oil and gas sector, offering safe and reliable contracting solutions to both the upstream and downstream components of these important projects," he added.

After more than a year of delays, Woodside's $14.9 billion Pluto project in Western Australia is finally up and running, with first production of liquefied natural gas expected within weeks.

Woodside chief executive Peter Coleman hailed the achievement of ready for start-up status as an important milestone as first gas entered the processing train on March 22.

"This milestone is a credit to all those involved in the construction of Pluto, which proudly takes its place as Australia's third LNG project," Mr Coleman said in a statement to the Australian Securities Exchange.

"While the achievement of ready for start-up is a significant moment, our operations team remains focused on the path to steady-state production," he said. "Maintaining our focus on safety and integrity is a priority through this process."

The Pluto LNG project is expected to contribute 17 to 21 million barrels of oil equivalent to Woodside's 2012 production.

It will add to Australia's roughly 20 million tonnes per year of output from the Woodside-operated North West Shelf venture and ConocoPhillips' Darwin plant.

Another seven LNG projects are under development in Australia.

Mr Coleman, who took over from Don Voelte as Woodside chief in May 2011, increased the budget for Pluto to $14.9 billion from an original estimate of $11.2 billion. It was the third time Woodside had lifted the budget for Pluto, making it the most expensive LNG plant in the world in terms of dollars per unit of capacity, according to some in the market.

One of Mr Coleman's first tasks in the new role was to announce another six-month delay in the start-up of the initial Pluto project, then due in August. Mr Voelte had held up Pluto as the fastest LNG project to go from discovery to start-up.

Woodside last month posted a 4.3 per cent dip in full-year profit to $US1.507 billion, weighed down by costs for the late delivery of the Pluto project, and higher costs for exploration, financing and taxes.

INDIA

Gujarat State Petroleum Corporation (GSPC) has targeted commissioning the five million tonnes liquefied natural gas terminal at Mundra in 2016, Gujarat principal secretary D J Pandian said in New Delhi. The Rs 4,000 crore terminal was earlier expected to be operational by 2014.

"Some preliminary work for the project has started… Site has been identified. It is planned to be commissioned in 2015-16," Pandian added.

The LNG terminal is designed to have two storage tanks. The terminal will have LNG receiving, re-gasification and gas evacuation facilities. The front-end engineering and design (FEED) contract has been awarded to Belgium-based Tractebel Engineering, according to the company website.

"Now GSPC will go for the detailed project report (DPR) and then issue the EPC (engineering, procurement and construction) contract in six months to one year’s time," Pandian said.

At present, Gujarat-based GSPC holds 50 per cent stake in the project. Also, Adani Group holds 25 per cent. Ruias’ promoted Essar group has earlier shown interest to share 25 per cent equity but later withdrew from the proposed transaction. Pandian indicated that getting a third partner is not tough and many players have shown interest to buy footprint in LNG business.

"We are not worried about it, there is lot of interest. In next six to twelve months, we will look for third partner after completing a certain level of work," said Pandian.

He also added, "There is lot of interest... Torrent and many others are there but somebody should take the lead."

At present, there are two operational LNG terminals in Gujarat operated by Shell and Petronet LNG. Demand for LNG is increasing as gas output from RIL-operated KG D6 falls.

India is hoping the construction of a proposed 5mn tpa LNG import terminal in Mundra, Gujarat will help address its growing import requirements. If all the proposed LNG import capacity expansion plans were to progress, the country's current capacity would rise from 12.5mn tpa to 33.5-35.0mn tpa. There could be some competition between plans in Gujarat and others in the wider west coast or even the east coast.

The Gujarat State Petroleum Corporation (GSPC) plans to commission the new liquefied natural gas terminal with a capacity of 5mn tonnes per annum (tpa) at Mundra, in Gujarat, by 2016. The announcement was made by the state's principal secretary for energy and petrochemicals, D. J. Pandian, on March 19. The project is expected to cost US$800mn (INR40bn) and will be 50% owned by GSPC, with another 25% in the hands of the Adani Group. Essar Group held the remaining 25% stake before pulling out of the project. Pandian commented on the withdrawal saying: 'In the next 6-12 months, we will look for a third partner after completing a certain level of work.'

India's two current LNG-receiving terminals, Dahej and Hazira, both located in Gujarat state, have a combined capacity of 12.50mn tpa (17.24bcm). The construction of a 2.50mn tpa (3.45bcm) plant at Kochi, in the southern state of Kerala, is expected to be completed by end-2012. Should the proposed 5mn tpa (6.90bcm) plant at Ratnagiri in Maharashtra get off the ground (when combined with a possible 5mn tpa expansion of the Dahej facility), India's LNG import capacity could rise to as much as 25mn tpa (34.47bcm).

According to BMI's forecasts, Indian gas imports are set to grow from an estimated 15.72bn cubic meters (bcm) in 2011 to 43.28bcm in 2021. If India actually builds 25mn tpa (34.47bcm) of LNG import capacity, there would still be sufficient room for projects worth another 6.39mn tpa (8.81bcm), based on BMI forecasts. The Mundra project would bring the country's import capacity to 30mn tpa (41.37bcm), falling only slightly short of our 2021 import forecast.

The Dahej, Hazira, Kochi and Ratnagari plants are all located on India's west coast, securing imports from suppliers in the Middle-East, Africa and the Atlantic. The proposed 5mn tpa (6.90bcm) plant in Mundra would take advantage of well established trade routes and would reaffirm Gujarat's dominant position in India's LNG market. Although the state's current monopoly will be affected by the construction of the Kochi and Ratnagari; assuming no other projects are built, the Mundra plant would help Gujarat retain a 75% stake in imports.

This geographical concentration raises clear risks to the security of supply. Plants which are not located in Gujarat are still located on India's west coast, which leaves India highly dependent on a limited number of suppliers. All of India' gas is imported in the form of LNG, and according to Cedigaz data, nearly 87% of all contracted volumes come from Qatar. This growing dependence on imports sourced from a limited number of countries poses a clear threat to the country's energy security. Iranian threats to close the Strait of Hormuz, through which 28% of the world's LNG cargoes and nearly all of India's gas supplies transit, have highlighted the risks stemming from this kind of dependence.

With Australian gas production set to grow exponentially over the coming years, and with many LNG export terminals in the pipeline, the prospect of building an LNG import terminal on India's east coast is gaining support. Plus, due to high transport costs and the numerous local taxes that have to be paid to bring imports from the west coast to the eastern part of the country, an LNG terminal on the country's east coast is also economically viable.

On January 13, GAIL India's subsidiary GAIL Gas signed a memorandum of understanding (MoU) with the government of Andhra Pradesh that will see the company build a US$971mn floating storage and re-gasification unit (FSRU)/LNG import terminal on India's east coast. The facility, which is to be located near Kakinada or Vishakapatnam in AP, will have a capacity of 3.50-5.00mn tpa (4.83-6.90bcm). The plant is expected to be completed by 2012-2013.

Similar east-coast projects, albeit less advanced, have been proposed as of late. On January 3, Royal Dutch Shell and Reliance Industries outlined their interest in creating an equal joint venture (JV) to build a US$560mn terminal in Kakinada. The two companies said that other firms, such as Petronet LNG, were also considering building a LNG terminal on the east coast.

BMI Asia Pacific Oil and Gas Insights current forecasts suggest that none of the LNG import projects are in direct competition. If the proposed Ratnagari, Mundra, Kakinada facilities and the Ratnagari expansion were all to be realized, India's import capacity would reach 33.50-35.00mn tpa (46.20-48.26bcm), 86%-90% of which would be located on the West Coast and 64%-67% in the State of Gujarat. With imports forecasted to hit 43.28bcm in 2021, overcapacity would only be 2.92-4.98bcm, up from 1.52bcm currently.

Indian Oil is planning to seek a foreign partner for its proposed $2bn (€1.5bn) liquefied natural gas terminal at the coastal province of Odisha in eastern India, company officials said in March.

Indian Oil will set up the 5 million tonne per annum (mtpa) terminal within the Dhamara port complex along the Bay of Bengal in collaboration with Dhamara Port Corporation Limited (DPCL), which owns and manages the port.

DPCL is a joint venture of Indian construction major L&T and Tata Group.

As with Indian Oil's search for a third foreign partner for its LNG terminal at Ennore in Tamil Nadu, the firm wants to ensure long-term imports.

The major is collaborating with Petronet LNG for the Ennore terminal.

"We are keen to bring in overseas partners for our LNG projects for comfort of long-term LNG supplies," the company official said.

"We have not been able to contract long term supplies as yet. [So] we will go ahead in [constructing] the Dhamara terminal based on spot merchant purchases of LNG as we have planned for the Ennore terminal.

"Closer to project commissioning or soon thereafter, we will negotiate for a foreign partner with expertise in operating a terminal as well as to ensure gas supplies," the official added.

The Dhamara LNG terminal, the first in eastern India, will primarily be a feedstock source for Indian Oil's 15mtpa refinery and petrochemical complex at the nearby Paradip petroleum, chemicals and petroleum investment region (PCPIR).

The remainder of the LNG output from the $6bn facility will be sold to other projects in the PCPIR.

The refinery has been scheduled for commissioning in the first quarter of 2013, a year behind the original schedule.

The Paradip refinery will produce 5.97m tonnes of diesel, 3.4m tonnes of petrol, 1.45m tonnes of kerosene and aviation turbine fuel, 536,000 tonnes of liquefied petroleum gas (LPG), 124,000 tonnes of naphtha and 335,000 tonnes of sulfur.

In addition, the company announced it will invest $5bn in a petrochemical complex linked to the Paradip refinery.

However, Indian Oil will only start building the petrochemical complex two years after production from the refinery has stabilized.

Indian Oil, the country's largest oil marketer-refiner with a refining capacity of 65.7mtpa, operates petrochemical complexes at Panipat in northern India and Gujarat in the west.

The company is expanding its footprint into LNG by operating a terminal at Dahej in Gujarat and is building another at Kochi in Kerala.

According to a forecast by India's Ministry of Petroleum, the country's demand for gas is expected to touch 381m cubic meters (cbm)/day by 2015 against its current supply at 202.9m cbm/day.

India has an LNG import capacity of 13.5m tonnes/day at two operational terminals.

Publicly listed state gas distributor PT Perusahaan Gas Negara (PGAS) has awarded the contract for the installation of a distribution pipeline in Medan, North Sumatra, to a business consortium consisting of state-owned Hutama Karya, Darma Empat Lima and Ilamaru Jaya.

The pipeline will deliver gas from the planned floating liquefied natural gas (LNG) terminal to be set up in Belawan. The pipes will be made by Krakatau Steel’s subsidiary, PT KHI Pipe Industries.

Under the contract, Hutama Karya and its partners will be tasked with design, construction, installation, pre-commissioning and commissioning. The consortium will install a 16-inch pipe which spans 11 kilometers, 12-inch pipe spanning 18 kilometers and an 8-inch pipe spanning 6.5 kilometers.

"The project also includes the installation of a supporting facility called a metering regulating station [gas flow control station]," the company’s spokeswoman Nella Andaryati told The Jakarta Post on March 8.

"The appointment of the consortium is key to the development of our business and the manifestation of our commitment to meet the demand for gas in North Sumatra," she said.

PGN expects that the Belawan FSRU, which is projected to have a total capacity of 140 million standard cubic feet per day (mmscfd), can begin commercial operation in 2013, although the initial target was in 2012.

The project has been in limbo since state oil and gas firm PT Pertamina announced its plan to convert the Arun LNG plant into a receiving terminal, and to supply gas to Aceh and North Sumatra.

However, separately, State-Owned Enterprises Minister Dahlan Iskan reported that the Belawan FSRU and Arun LNG receiving terminals would be synchronized.

"Arun will deliver gas to Belawan through a pipeline which will be constructed by Pertamina from Arun to Pangkalan Brandan in North Sumatra. From Pangkalan Brandan to Belawan, the gas will be channeled through an existing pipeline," he said as quoted by tempo.co.

Dahlan said that Pertamina aimed to complete the pipeline within 18 months. The pipeline will be buried under PT KAI’s railway track in Sumatra. "This way, permit issues will be easier to solve," he said.

As for PGN’s Belawan FSRU, Dahlan said the LNG terminal would supply gas to South Sumatra and Lampung. The gas will then be used for state power company PT PLN’s gas-fired plants in Cilegon, Banten, and Muara Tawar in Bekasi.

PGN currently operates natural gas transmission and distribution pipelines spanning more than 5,900 kilometers. The firm distributes the gas to power plants, industries, commercial businesses and households across the country.

In the first nine months of 2011, the company recorded a net profit of US$495.33 million (Rp 4.51 trillion). At the same time, PGN distributed 785 billion British thermal units (Btu) per day of gas to customers, down from 821 billion Btu per day over the same period in 2010.

A protest against Papua New Guinea's massive ExxonMobil PNG LNG project has led to its suspension according to a statement from ExxonMobil subsidiary Esso Highlands on March 15. According to Esso Highlands "work has been temporarily suspended" at the Hides Gas Conditional Plant site as a result of a landowner group undertaking what the company termed "illegal stop-work activities".

The local Post-Courier newspaper reported that the interruptions began March 12. The paper quoted "landowners spokesperson" Henry Parilia as saying that the interruptions were "mainly to do with the government payout of IDGs [Infrastructure Development Grants] to the Hela Transitional Authority [HTA]". Parilia stated that the payments, which he says should have gone to his landowner group, had been "hijacked" by the HTA. The Hides site was originally located in Southern Highlands Province. However, it is part of the area that has been carved out of that province to create the new province of Hela, contributing to the confusion.

There is a widespread confusion among landowners about the benefits that the LNG project will provide. The Asian Development Bank recently reported that Papua New Guinea is unlikely to experience significant earnings from the LNG project until around 2023. Even then it will take time for the benefits to trickle down to landowners. There is also competition between a diverse array of landowner groups, middle men, opportunists, local authorities, and provincial governments over the disbursement of monies relating to the project.

Earlier in March there was unrest in the capital Port Moresby after landowners demanding the payment of grants related to the project were told the money would be paid out in the provinces; suggesting that some of the protesters may not have been genuine claimants. Further disruption to work on the project site is probable in the months and years ahead. It appears most likely that the rate of disruption will increase as time passes and expectations remain unfulfilled.

Tokyo Gas Co. said March 5 that it has reached an agreement with a Vietnamese gas supplier to cooperate in liquefied natural gas-related businesses in the Southeast Asian country.

Tokyo Gas will support Petrovietnam Gas, a unit of Vietnamese government-owned oil company Petrovietnam, in such fields as personnel training for the operations of LNG terminals and exchanges of information on technologies for downstream gas utilization.

Through the cooperation, Tokyo Gas aims to gain a foothold for LNG infrastructure and gas supply services in Vietnam.

Tokyo Gas has already received an order for the basic design of the Thi Vai terminal for LNG from Vietnam. It hopes to win an order for the construction of the terminal.

The company is also looking at investing in an LNG thermal power plant to meet growing electricity demand in the Vietnam as its economy expands rapidly.

Tokyo Gas and Petrovietnam Gas will hold further discussions on details of their cooperation.

Noble Energy Inc. is preparing to lay an underground pipeline from Block 12 to Cyprus, according to media reports on the island. The pipeline is reportedly part of a venture to set up an LNG terminal off Cyprus's southern coast that will enable the liquefying gas for export to Europew and Asia. The pipeline would be 300 kilometers long and the cost is expected to reach $2 billion.

The cost of the LNG terminal will be about $8-10 billion. Experts and commentators in Israel believe that the economic justification is border-line for an LNG infrastructure and export for the amount of gas discovered so far in Cypriot waters. Therefore additional quantities of gas are required from Israeli gas fields or future discoveries in Cypriot waters.

Israel is yet to announce if it will support a partnership in a Cypriot LNG installation or prefer to set up its own installation in Israeli waters. The decision is expected to be taken only after publication of the recommendations of an inter-ministerial headed by Shaul Tzemach on Israel's gas production sector. Publication of the recommendations is expected at the end of March after being postponed for 30 days.

According to reports in the Cypriot media, Nobel has leased the services of the research ship Odin Finder, which flies the Italian flag. The ship is already mapping the seabed along the route of the planned pipeline. Noble recently reported that the Aphrodite field in Block 12 may contain 5.2 trillion cubic feet of natural gas. The field borders Israel's economic waters and part of the strata could run over into the Pelagic license of Teddy Sagi and Beny Steinmetz.

Noble Energy owns 70% of Block 12's rights while Delek Group Ltd. units Delek Drilling LP and Avner Oil and Gas LP own 15% each.

Construction of the Hauts de France II natural gas corridor began on March 1, according to a statement released by France's main transmission system operator (TSO) GRTgaz.

The pipeline will stretch 191km from Loon-Plage to Cuvilly and connect the Dunkirk LNG terminal with the French network when it comes online by the end of 2015.

This year, GRTgaz plans to build a 51km section of the pipeline between Pitgam and Nédon, at a cost of E150m. In 2013, work will focus on two more sections - connecting Nédon to the interconnection point of Cuvilly and the Dunkirk LNG terminal entry point of Loon Plage to the interconnection point of Pitgam - costing E350m.

Annual capacity at the LNG terminal is expected to range between 10 billion-13 billion cubic meters/year (Gm³), but GRTgaz could not provide more details of pipeline capacity.

According to the TSO, the capacity would depend on the market's demand for gas coming from the LNG terminal of Dunkirk, which will have a regasification capacity of 13Gm³/year.

The Hauts de France II natural gas corridor is part of a larger project that includes an additional 300km pipeline, called Arc de Dierry, which connects Cuvilly to Voisines in Haute Marne.

The whole corridor, running from Dunkirk to the central and the south-eastern French regions, will transport gas coming from the new LNG terminal and from the interconnection points of Taisnières, at the border with Belgium, and Obergailbach at the border with Germany.

The TSO plans to spend E1.2bn on the connection. Of this sum, GRTgaz plans to invest E1.1bn in infrastructure improvements to the Hauts de France and to the Arc de Dierrey pipelines in total.

This is a similar sum to the total cost of the LNG facility itself. The Hauts de France II pipeline is expected to cost E500m.

GRTgaz has plans to invest E8bn in infrastructure, according to its 10-year investment plan announced last year.

Gazprom has revealed plans to proceed to the next stage in implementing the project for LNG plant construction near Vladivostok in Russia.

The specialized structural units of Gazprom were asked to elaborate on the investment rationale for the project in the first quarter of 2013.

Last January, Gazprom and the Agency for Natural Resources and Energy under the Japanese Ministry of Economy, Trade and Industry have signed an agreement for the preparation of a joint feasibility study on the options for natural gas use near Vladivostok as well as for natural gas and gas chemicals sale and transmission from the vicinity of Vladivostok to potential customers in Asia-Pacific countries.

The feasibility study defined economic conditions for the LNG plant construction in Vladivostok and confirmed its technical feasibility and the availability of a market niche for producing about 10 million tons of liquefied natural gas per year.

The study showed that 2017-2020 is the most favorable period for Gazprom to start supplying its liquefied natural gas from the vicinity of Vladivostok to the Asia-Pacific market.

In addition, preliminary analysis was also carried out to consider possible construction of a compressed natural gas production and supply facility and risks and issues related to the project were also identified.

Bahrain will award a tender to build a liquefied natural gas import terminal by the end of this year, the nation’s oil minister said.

The Gulf state plans to import 400 million cubic feet of natural gas, Abdul Hussain Mirza said today in an interview in Kuwait at a meeting of the International Energy Forum, adding that the country was producing 1.5 billion cubic feet of the fuel. He didn’t specify a timeframe for the imports.

The nation plans to expand a crude pipeline from Saudi Arabia to Bahrain by 120,000 barrels a day to 350,000 barrels. The facility, estimated to cost an initial $350 million, will be built by 2014, Mirza said. Extra oil volumes from the link will be used in the local refinery, which will also be upgraded.

Abu Dhabi's investment company Mubadala is to start work on a strategic floating LNG import and re-gasification unit facility which will avoid the Strait of Hormuz.

The UAE's energy security has been at issue as international pressure against the Iranian regime over inspections of its nuclear program has been met with defiant rhetoric and shows of strength by the Revolutionary Guard in the Strait.

The emirates have required more gas than they have produced since 2007.

Mubaladala has not yet given details of contracting for the design or construction of the terminal or attendant pipeline, though Bloomberg reports a feasibility study for the terminal has been completed. The unit will be constructed in two phases, reaching a final import capacity of1.2 billion standard cubic feet of un-liquefied gas per day.

The UAE has already taken some steps to mitigate its exposure to Iranian naval capabilities in the Strait. A pipeline from Habshan in Abu Dhabi to Fujairah has been constructed, and after issues between the contracting parties and ADCO will see crude from Abu Dhabi's onshore fields pumped onshore past the Strait.

Mubadala is a partner in the Dolphin project, a pipeline with transports Qatari gas to Abu Dhabi, Dubai and Oman.

Inter-GCC power politics and a desire by Qatar to realize the highest price possible for its gas have stymied progress on a more comprehensive pan-GCC gas network. Qatar is set to maintain a moratorium on gas export projects until at least 2015, which precludes further negotiation for the UAE and Oman to acquire further gas through the Dolphin pipeline.

The standoff between Qatar and its potential GCC customers has driven Qatar's neighbors to pursue some extreme gas projects of their own, from the Empty Quarter in Saudi - which has largely been a failure - to the hazardous Shah ultra-sour gas field in Abu Dhabi.

Iran seems to have reassured Gulf neighbors recently with both a former head of Saudi Aramco and Kuwait's ruler Sheikh Sabah al-Ahmad al-Sabah both telling the media that Iran will not close the Strait.

Mubadala confirmed that the project was underway. The terminal is slated to accept its first LNG imports in two to three years' time.