LNG UPDATE
October 2011
McIlvaine Company
TABLE OF CONTENTS
Wartsila, Shell Sign Agreement to Promote LNG as Marine Fuel
Wartsila Reports Dual-Fuel Engine Technology Milestone Track Record
Shell to Get LNG into Local Transport Market by Building Alberta Plant to Supply Truck Fuel
British Columbia Creates Plan to Encourage LNG Industry Growth
Royal Vopak, Enagas Complete Mexican Altamira LNG Terminal Buy
Argentina YPF to Invest $200 Mln in Regasifcation Plant
LNG Limited Wins Gas Pipeline License Approval for Gladstone LNG Project
John Holland Wins Curtis Island GLNG Contract worth in Excess of $90 Mln
Woodside Energy Eyes Subsea Fiber Links for Browse LNG
GE Enters Contract with Technip to Supply Compressors for Prelude FLNG
Wheatstone Project Gains Federal Environmental Okay
Fluor Awards Clough Downer JV a circa $600 Mln GLNG Contract
Chevron and Partners OK $29 Bln Wheatstone LNG Project
Hess Awards Expro $6 Mln-plus for NW Shelf Drilling Appraisal Contract
BP Looking To Buy Equity Stake in and Build LNG Terminals in India through Reliance Industries JV
India’s Pradesh Government Requests to Build LNG Terminal
Britain's BG Group Eye’s Stake in ONGC's KG Block with Investment in LNG Terminal
Indian Oil Considering Second East Coast LNG Gas Terminal as Part of Paradip Refinery Complex
Japan to Provide Financial Support toward LNG Exploration and Development
Inpex Making Progress in Naoetsu Receiving Terminal with 2014 Start
Samsung Heavy Develops Membrane–type Cargo Hold for LNG Tankers
Stats Group Completes Trunk Lines Isolation Project at Petronas LNG Complex
Hyundai Heavy Wins $400 Mln LNG Carrier Order
First UK FLNG Terminal Faces Year Delay Due to Regulatory Hold-ups
Ukraine Selects Socoin for LNG Regas Terminal Feasibility Study
Iraq Energy Committee Ok’s $13 Bln LNG Deal with Shell, Mitsubishi
Qatar's Rasgas Plans LNG Unit Maintenance Shutdown in January
Wartsila, the marine industry's leading solutions provider, and Shell Oil Company have signed a Joint Co-operation Agreement aimed at promoting and accelerating the use of liquefied natural gas as a marine fuel. The agreement was signed in August 2011 and will run for several years.
Supplies of low cost, low emissions LNG fuel will be made available to Wartsila natural gas powered vessel operators, and other customers by Shell. The Joint Cooperation Agreement will focus first on supplies from the U.S. Gulf Coast, and then later expand their efforts to cover a broader geographical range.
Gas fuelled marine engines are seen as being a logical means for ship owners and operators to comply with increasingly stringent environmental legislation. This agreement aims at increasing and easing the availability of natural gas for marine engine use, as well as developing the supply chain and infrastructure to facilitate the bunkering of LNG fuel. The two companies will jointly move these developments to marine markets in order to enhance its rapid introduction and use.
Wartsila has been at the forefront in the development of dual-fuel engine technology, allowing the same engine to be operated on both gas and diesel fuel. This dual-fuel capability means that when running in gas mode, the environmental impact is minimized since nitrogen oxides (NOx) are reduced by some 85 percent compared to diesel operation, sulfur oxide (SOx) emissions are completely eliminated as gas contains no sulfur, and emissions of CO2 are also lowered. Natural gas has no residuals, and thus the production of particulates is practically non-existent.
In addition to the environmental benefits that LNG fuel offers, the shipping industry is increasingly looking to gas as a means of reducing operating costs. With fossil fuel prices, and especially the cost of low carbon marine fuel, likely to continue to escalate, gas is an obvious economic alternative. In promoting gas propulsion, the two companies aim at reducing client risk, thereby accelerating market demand.
"It's an exciting time for the industry to have Shell, a major player, committed to increasing the availability of clean natural gas as a marine fuel. The marine community is becoming increasingly aware of the benefits provided by Wartsila natural gas engines as a means of reducing both costs and the environmental footprint. Natural gas engines represent a rare win-win, capturing emissions reduction and operational savings," says Christoph Vitzthum, Group Vice President, Wartsila Services.
Drawing from decades of experience in the development and application of natural gas engines for both the power generation and marine industries, Wartsila is the global leader in this advanced technology. "Clean, safe natural gas represents a true shipping paradigm shift; years ago it was sail to steam, then came the move from steam to diesel, and now it's a new era for gas propulsion," says Jaakko Eskola, Group Vice President, Wartsila Ship Power.
"We are pleased to work with Wartsila to move forward with this significant step in introducing LNG-powered vessels into the U.S. market, providing a clean, abundant and affordable fuel option," said David Lawrence, Shell's executive vice president Exploration and Commercial.
Wartsila's dual-fuel engines have exceeded 3 million running hours in both land-based and marine applications. This milestone represents a dual-fuel technology track record that cannot be matched by any other engine manufacturer.
Wartsila, a global leader in complete lifecycle power solutions for the marine and energy markets, is the recognized frontrunner in dual-fuel engine technology. The Wartsila DF engine series is increasingly the power solution choice for utilities and energy companies, as well as for all segments of the marine industry, worldwide. With the engines having passed 3 million hours of reliable and efficient operation, the effectiveness of this technology is proven. Today, the total number of Wartsila DF engines delivered to both marine and land-based applications is 470.
Dual-fuel engine technology provides the flexibility to switch between the use of natural gas and heavy fuel oil (HFO), light fuel oil (LFO) and various other liquid fuels. This flexibility in fuel choice offers numerous tangible benefits, both economic and environmental. With oil prices fluctuating and environmental regulations becoming increasingly stringent, the operator has the freedom to select the most cost-effective and readily available fuel, whilst also having the ability to utilize natural gas in order to comply with emission limitations.
Success in both land-based and marine applications
"For the power plant business, Wartsila's dual-fuel technology offers the perfect bridging solution for switching from liquid fuel to natural gas. The use of natural gas in power generation is rapidly increasing, but many locations are currently without a ready gas supply. Our dual-fuel technology enables customers in such areas to generate electricity, first with HFO and then to switch later to gas once it becomes available. Having now exceeded 3 million hours of reliable and efficient operation, there can be no doubt as to the effectiveness of this technology," says Vesa Riihimaki, Group Vice President, Wartsila Power Plants.
"A transition to LNG fuel is one of the most realistic options for significantly reducing the environmental footprint in marine transportation. Carbon-based greenhouse gas emissions can be reduced by at least 15 percent, while sulfur and nitrogen oxide emissions are practically entirely eliminated. Dual-fuel technology is the spearhead of Wartsila's engine portfolio, and is leading the marine sector towards a more sustainable future," says Juhani Hupli, Vice President, Ship Power Technology, Wartsila Ship Power.
Wartsila began developing dual-fuel gas engines in 1987, the first concept being the gas-diesel (GD) engine with high-pressure gas injection. This was initially developed for the marine offshore market, where it has been successfully applied in numerous floating production units. The second generation of gas engines was introduced in the early 1990s as spark-ignited (SG) pure gas engines. The real breakthrough, however, came when the dual-fuel (DF) engine was introduced by Wartsila in 1995. The DF engines utilize low pressure gas, and combine fuel flexibility with environmental performance and fuel efficiency.
Royal Dutch Shell Plc will build a liquefied natural gas plant in Western Canada as it looks to boost demand for its abundant gas reserves by promoting LNG as a truck fuel.
Shell wants to build a small-scale LNG plant at an existing gas-processing facility in the province of Alberta. The plant would supply the local market with fuel for trucks.
"LNG for trucks is definitely growing, but it is still a niche market focused on fleet and trucks because they are diesel intensive. But with more expensive diesel and cheaper natural gas, this may change," said Dave Hurst, senior analyst at Pike Research in Detroit.
Designed to produce fuel for heavy-haul trucks, the plant will supply LNG to Shell's Flying J truck stops in the Alberta cities of Calgary, Edmonton and Red Deer. The network could eventually expand to the neighboring province of British Columbia.
"It's really small-scale liquefaction compared to the typical LNG plants that Shell has been into for 45 years," said Bob Taylor, manager of commercial fuels, business development and marketing for the company's Canadian unit. "We're there to get LNG into the transport market for use (locally) ... LNG is typically produced to take it to markets quite a ways away."
Shell is joining other big producers looking to boost use - and the price - of natural gas by touting it as a transportation fuel. Natural gas production has climbed in recent years and prices have sagged as prolific new shale-gas deposits are tapped.
Along with its new push into the trucking market, the company is also teaming up with equipment manufacturers to raise interest in the fuel among railways, miners and the marine shipping sector.
Encana Corp, Chesapeake Energy Corp and other natural gas producers are also promoting the gas to power big trucks, backing a plan put forth by Texas financier T. Boone Pickens, who says the switch could cut U.S. oil imports by 2.5 million barrels per day.
The new plant would produce 0.3 megatonnes per year of LNG. In comparison Qatargas, the world's largest LNG producer, can handle up to 42 megatonnes a year.
Shell will build the plan at its Jumping Pound gas plant, about 19 miles (30 kilometers) west of Calgary. Work is expected to be completed by 2013. The company declined to say how much the facility will cost to build.
Shell will begin selling LNG at the Alberta Flying J truck stops next year, relying on third-party supplies until its own plant is complete.
It is also teaming up with Westport Innovations Inc, a Vancouver company that develops natural-gas powered engines, to encourage transport companies to switch over to the fuel and develop standards for its use.
In a separate release, Westport said it expects the partnership will help boost natural gas as a transportation fuel.
"As a result of this initiative, we believe the use of natural gas as a fuel for transportation will accelerate," David Demers, Westport's chief executive, said in the statement.
As part of "Canada Starts Here: The BC Jobs Plan", formally released on September 22, Premier Christy Clark announced British Columbia will take four key steps to create a prosperous liquefied natural gas industry and jobs, including making the Kitimat liquefied natural gas plant operational by 2015.
"Creating a new industry with the capacity to export B.C.'s natural gas to overseas markets for the very first time will instantly increase economic prosperity and create jobs," said Premier Clark. "By adopting a more aggressive approach to the development of the natural gas sector, I am confident British Columbia can create a prosperous LNG industry that will bring local jobs to our communities and deliver important dollars into our economy."
The four steps government will take to grow a viable LNG industry in British Columbia are:
Clark stressed the first step will be to accelerate the lengthy permitting processes and improve the decision making required to bring large-scale production facilities from a concept to a reality, and that these commitments will be a greater priority for B.C. on a go forward basis. The Province will also continue to strengthen collaboration with First Nations, local communities, industry partners and other levels of government to define more effective working relationships.
Secondly, in the area of training and development, the Province has been working with industry partners for some time on the future skills required to support a new LNG industry. The goal is to ensure the post-secondary system is able to deliver the targeted training necessary to grow the oil and gas industry, including LNG. Final details are under consideration with further details to be announced later this fall.
Thirdly, the Premier has asked key provincial officials to attract investment by working with industry stakeholders and First Nations to remove the barriers and secure the investment required to establish up to three LNG plants by 2020. As of today, the Province is aware of a handful of LNG proposals.
Presently, the most advanced project is the Kitimat LNG terminal proposed by Apache Canada Ltd., EOG Resources Inc, and Encana Corporation. This terminal is located on Haisla Nation territory. Kitimat LNG and the connecting Pacific Trail Pipeline have received the required environmental approvals. The Province continues to work with other levels of government and the project's proponents to ensure it becomes operational.
"The Kitimat LNG facility will allow north western British Columbia to diversify its economy and open up the trade opportunities to the Asian markets," said Tim Wall, president of Apache Canada. "It is thanks to government leadership that we look forward to working in B.C. for many years to come."
"The Province's assistance is timely," said Haisla Nation Chief Councillor Ellis Ross. "Our own training capacity is limited by resources and capabilities, and these have been exhausted given the projects now underway on our territory and the demands they place on our people for skills and training. Our economic future has never looked better, and this assistance will help us deliver on this promise to our community."
Once completed, the Pacific Trail Pipeline will connect natural gas from the Western Sedimentary Basin to the Kitimat LNG facility. Natural gas liquefied at the Kitimat LNG plant would be transported by vessels to markets primarily located in the Asia Pacific Region.
These two projects are each expected to create approximately 1,500 person-years of work during construction. The export terminal will create 120-140 permanent positions once it is in operation. In addition to these jobs, a successful LNG export operation would keep exploration and production activities at a high level across northeast B.C., and keep service sector workers in demand for decades.
The fourth step is international marketing and trade development. Clark confirms that LNG will be an important focus of her upcoming trade missions to Asia. The goal is to begin the discussions needed to open up markets for British Columbia LNG exports.
Currently, the National Energy Board (NEB) is considering an application from Kitimat LNG for a 20-year license to export natural gas in the form of liquefied natural gas. If approved, it would be Canada's first export license for liquefied natural gas. The NEB is also currently considering an export license application for the smaller Douglas Channel partnership project.
"We continue to make strides in raising market awareness, and today is another step in a longer-term process," said Clark. "British Columbia is highly regarded as a safe and responsible location to do business. Liquefied natural gas is an exciting development that will open up thousands of new jobs and billions of dollars in investment for our province in the years ahead."
B.C. is poised to attract new investment into our economy, creating and protecting jobs for families in every region. This is at the heart of "Canada Starts Here: The BC Jobs Plan." The plan has three pillars to help us deal with today's economic uncertainty and emerge from it stronger than ever:
The joint venture of Vopak (60%) and Enagas (40%) has successfully completed the previously announced acquisition of the LNG storage and regasification terminal in Altamira, Mexico.
The jointly controlled entity has acquired 100% of the shares in the terminal from Shell (50%), Total (25%) and Mitsui & Co LTD. (25%) for US$408 million. The completion of the transaction follows the announcement on June 2, by Vopak and Enagas. The joint venture has taken over operational management of the terminal with immediate effect after having been granted the required government approvals recently.
For Vopak this is the second independent regasification terminal for LNG following the opening of Gate terminal (Netherlands) in September this year, while for Enagas it is the fifth LNG terminal and the first terminal outside Spain. This underlines the worldwide developments in the LNG market, requiring independent third-party LNG import and regasification terminals in regions that show a structural (increasing) imbalance between the demand and supply of natural gas.
The LNG terminal in Altamira will continue to facilitate overseas LNG imports and supply of gas into Mexico and has been operational since 2006 under the highest safety and technical standards applicable for the LNG industry. The terminal consists of 2 fully operational tanks of 150,000 cubic meters (cbm) each and a jetty capable of receiving LNG vessels with a capacity of up to 216,000 cbm. The terminal has a throughput capacity of 7.4 billion cubic meters per annum (bcma), which is fully contracted for a long-term period. The capacity can be expanded up to 10 bcma by building and operating a third tank.
For this acquisition the joint venture successfully concluded a US$300 million senior non-recourse financing agreement with a banking syndicate of international relationship banks. The debt facilities will have a maturity of 10 years with an annual repayment profile. The debt facility is based on variable interest rates, but will be substantially hedged to mitigate the potential interest exposure.
The syndicate of banks consists of Banamex, BBVA Bancomer S.A., Citi, Credit Agricole Corporate and Investment Bank, ING Bank N.V., CaixaBank S.A., Mizuho Corporate Bank, Ltd., and Banco Sabadell, Miami Branch. Mizuho Corporate Bank, Ltd. acted as financial advisor for this transaction. ING Bank N.V. acts as the Facility Agent of this transaction while Addleshaw Goddard acted as legal advisor to the joint venture. The syndicate of banks was advised by Linklaters.
YPF SA, the Argentine unit of Spain's Repsol YPF SA, will invest $200 million to build a regasification plant in the port city of Bahia Blanca, a person familiar with the matter said September 29.
YPF already has a regasification vessel operating in Bahia Blanca and one in Escobar, which together process about 20 million cubic meters of gas per day.
Gas from the regasifcation plant will be distributed throughout Argentina to meet the country's growing need for power.
Demand for natural gas and electricity has soared in recent years amid booming economic growth.
Liquefied Natural Gas Limited announced that the Queensland Government has granted Pipeline License (PPL) 161.
LNG Limited’s wholly owned subsidiary, Gladstone LNG Pty Ltd is now able (subject to various license conditions) to connect future gas supply from the Callide Infrastructure Corridor to the Company’s wholly owned LNG project at Fishermans Landing, in the Port of Gladstone (LNG Project).
The pipeline will initially be capable of supplying 520 TJ/day (180 PJ/year) for the 3 million tonne per annum LNG Project but has expansion capabilities.
John Holland has announced it has been awarded a marine subcontract worth in excess of $90 million which forms part of the works for GLNG’s proposed Curtis Island LNG facility.
Under the subcontract, to be delivered for GLNG’s EPC contractor Bechtel Australia Pty Ltd, John Holland will design and construct a new product loading facility comprising a 360-meter jetty and loading platform.
Included in the contract scope is the procurement, fabrication, construction and commissioning of the structural, mechanical and electrical components of the product loading facility.
John Holland Group Managing Director, Glenn Palin, said: “Today’s announcement follows our recent success with GLNG’s project for the construction of marine offloading facilities and builds on our long history in delivering of large-scale marine infrastructure works in the energy and resources sector.
“This project will draw on our industry leading capabilities in this area, underpinning our strategic push into the LNG sector.” General Manager of John Holland’s Minerals & Industrial business, David Balmer, said: “This is a significant project for John Holland, aligned to the long term strategy of our business and our continued expansion into the LNG sector.”
The contract builds on John Holland’s recent success in the energy and resources and minerals sectors, following a recent contract win for Chevron’s Gorgon development and a FEED contract win for Woodside Energy’s Browse LNG development in Western Australia, and the ongoing delivery of Apache Energy’s Devil Creek onshore gas plant, also in Western Australia. John Holland also continues to deliver the major marine infrastructure expansion projects across Australia, including expansion works at the Cape Lambert Port B project in Western Australia, and completed expansion works at the Abbot Point Coal Terminal in Bowen, Queensland and the Dalrymple Bay Coal Terminal in Mackay, Queensland.
Construction of the new product loading facility will commence in August with completion expected in 2013.
Woodside Energy will complete a desktop feasibility study of a 320-kilometer subsea optic fiber link for the Browse liquefied natural gas precinct in approximately three months.
The proposed fiber optic cable will connect an onshore LNG production and export plant at James Price Point to a central processing facility (CPF) located offshore, according to a network schematic.
James Price Point is about 60 kilometers north of Broome in Western Australia.
Fiber optic links will then run from the CPF to two offshore platforms situated over the Brecknock and Calliance gas and condensate fields, where the water is about 590 meters deep.
The fields are located about 400 kilometers off the Kimberley coast.
Woodside is the major equity holder and operator of the Browse LNG development. Other shareholders include BHP Billiton Petroleum, BP, Chevron and Shell.
The development is entering a detailed front-end engineering and design (FEED) phase.
A final investment decision is expected by the middle of next year. If that occurs, the first gas from Browse will be processed by 2017.
A Woodside spokesman said the firm has completed "several studies" on fiber optic connections to various assets in the Browse LNG development, pointing to the cable path included in the schematic.
Details of the latest desktop study are expected to inform the engineering design, installation and commissioning of the fiber optic cable.
A repeater-less subsea fiber optic transmission system is one option being considered for Browse.
Repeater-less technology could bridge distances of 400 kilometers or more without requiring submerged electrical power or active elements, according to a study [pdf] of the technology's use in oil & gas fields.
Single-mode fiber optic cable options are also understood to be under consideration, conforming to the ITU-T standards G652.D [pdf] or G655.
The plan for Browse LNG includes a third gas and condensate field called Torosa, which is to be developed in phases.
The Browse subsea network schematic shows a proposed optic fiber link to connect the CPF to the platform at Torosa; however, it is unclear if this is included in the 320 kilometers of fiber currently under consideration.
GE Oil & Gas has entered into an agreement with Technip to supply two steam turbine-driven compressors for the Shell Prelude Floating Liquefied Natural Gas (FLNG) project. The facility, which is to be based offshore Australia, will be the largest floating offshore facility in the world. Technip and Samsung Heavy Industries (SHI) formed a consortium (TSC) which Shell has tasked to engineer, procure, construct and install the Prelude FLNG facility.
The GE compression trains will be vital elements of the liquefaction process, which cools natural gas to its liquid state. In addition to the supply of the steam turbines and compressors; the scope of GE's agreement with Technip, France includes start up and two years of training, operation and spare parts.
"This is a milestone achievement for GE, marking the first order in the FLNG industry for main refrigerant trains," said Prady Iyyanki, president and CEO—turbomachinery equipment for GE Oil & Gas. "This is a very promising market and will be a focus of our growth efforts in the future."
The Shell Prelude FLNG facility will measure 488 meters from bow to stern and will weigh around 600,000 tons when fully loaded. It will contain 260,000 tons of steel, and its deck area will be longer than four football fields. The capacity of the on-board storage tanks will be equivalent to 175 Olympic swimming pools.
Shell's FLNG facility will be moored at the Prelude gas field, about 200 kilometers off Western Australia's Kimberly Coast. Offshore fields such as Prelude may hold significant quantities of natural gas, but many are at great distances from land or the nearest pipeline. Tapping into these "stranded" gas resources has been nearly impossible until now. The Shell FLNG facility addresses this industry challenge.
"Since an FLNG plant is on a floating structure, the key critical-to-quality challenges are robustness, weight and footprint, extension of performance curves and reliability. GE has offered a solution that will meet those requirements," said Joel Leroux, TSC Shell FLNG consortium project director.
GE Oil & Gas is a leader in LNG applications. To meet the specific requirements of the Shell Prelude project, GE is minimizing the casings of the steam turbines and centrifugal compressors to reduce weight and footprint. GE is designing the compression trains to cover a wide range of operating conditions, developing a technology for potential use in future FLNG plants at different sites.
GE also will build a new facility for testing centrifugal compressors and will perform a partial load string test for the steam turbine-driven compressor trains.
The Shell Prelude project further expands GE's growing presence in the Australian oil and gas sector. GE has been a key equipment supplier to different companies for a variety of onshore projects in the country, including the development of Gorgon, one of the world's largest untapped natural gas fields.
With this project the total value of LNG contracts awarded globally to GE, by different companies, in the first nine months of 2011, reaches the value of $1 billion, confirming GE's successful trend in supplying onshore, offshore and floating LNG projects.
Chevron Corp. on September 22 received Australian Commonwealth Government approval by the Federal Environment Minister, the Hon. Tony Burke, MP, for its Wheatstone Project in Western Australia.
George Kirkland, vice chairman, Chevron Corp., said, "We welcome the Australian federal government's support for the Wheatstone Project. The federal environmental approval is an important milestone in reaching the final investment decision for the Wheatstone Project this year."
The foundation phase of the project will consist of two liquefied natural gas trains with a combined capacity of 8.9 million tons per annum (MTPA) and a domestic gas plant. It is scheduled to start production in 2016. The environmental approval allows the project capacity to increase to 25 MTPA.
Melody Meyer, president, Chevron Asia Pacific Exploration and Production Company, said, "Wheatstone and the previously sanctioned Gorgon project position Chevron as a major LNG operator delivering energy, jobs and economic benefits to Australia, as well as helping to meet long-term demand growth for cleaner burning fuel in the Asia-Pacific region."
Roy Krzywosinski, managing director, Chevron Australia, said, "The Wheatstone Project is one of Australia's largest resource projects and is ideally situated to process natural gas produced by Chevron-operated permits, and third parties, from the prolific western Carnarvon basin, one of Australia's most prospective areas for energy development."
The plant site is located in the Western Australian State Government's Ashburton North Strategic Industrial Area, approximately 7.5 miles (12 kilometers) south of Onslow on the Pilbara coast.
The Wheatstone onshore foundation project is a joint venture between the Australian subsidiaries of Chevron (operator 73.6%), Apache (13%), Kuwait Foreign Petroleum Exploration Company (7%) and Shell (6.4%).
Clough announced that the Clough Downer Joint Venture (CDJV) has been awarded a circa $600MM unit rate re-measurable contract by Fluor for construction of pipelines, compression facilities and associated infrastructure relating to the Fairview component of the Santos GLNG project, located in the Surat Basin.
CDJV is a 50/50 joint venture between Clough and engineering and infrastructure management services group, Downer Australia (Downer).
The scope of work involves the construction of over 400km of gas and water transmission pipelines, two compression facilities, and an 800 person camp. Expansion of the existing Fairview compression facilities also forms part of the scope. Construction work was due to commence in September 2011. At peak the project will employ a workforce of 650.
"This is a significant project award and represents a breakthrough for our recently established Coal Seam Gas division into the expanding Queensland Coal Seam Gas industry. We will utilize resources and expertise from across the company and will work with our partner Downer to deliver the best possible project outcomes to Santos and their partners for this groundbreaking CSG to LNG project," said Clough's Chief Executive Officer John Smith.
The Chief Executive Officer of Downer, Grant Fenn, said this is another major win and Downer was pleased to be extending its relationship with Clough.
"We have a compelling service offering and an expanding footprint in the growing Oil & Gas sector," Mr Fenn said.
The GLNG pioneering project to convert coal seam gas (CSG) to liquefied natural gas (LNG) for export to global markets represents a major investment in a cleaner energy source for the future. The Project sources gas from Santos' gas fields in the Bowen and Surat basins and transports the gas via a 420-km underground pipeline to a two-train LNG plant with a nameplate capacity of 7.8 million tonnes per annum on Curtis Island, Gladstone. GLNG is a joint venture between Santos and three of the world's largest LNG companies, PETRONAS, Total and KOGAS.
Chevron Corp and partners placed a US$29 billion bet on Asian demand for clean-burning fuels September 26 by approving construction of the Wheatstone gas-export project in Australia, overlooking near-term worries about the global economy and competitive threats posed by new energy sources such as shale gas.
Chevron said it aims to ship the first cargo of liquefied natural gas, or LNG, from Wheatstone on the coast of Western Australia state to Japanese customers in 2016 and the facility could more than double in size later to satisfy regional energy consumption growth.
"At this point we've actually become slightly more bullish on gas demand coming out of Asia," George Kirkland, Chevron's vice-chairman, told Dow Jones Newswires in an interview.
This partly reflects expectations Japan will import more LNG as it seeks alternative fuels to nuclear power in the wake of the crisis around its quake-hit Fukushima Daiichi reactors, he said.
Wheatstone's approval means international energy companies have now committed to spend over US$120 billion to develop reserves of natural gas held off Australia's northern coast and trapped stores of methane in eastern Queensland state's coal seams, moves that could catapult the country ahead of Qatar as the world's largest exporter of LNG within a decade.
The investment boom in Australia underscores the difficulties that Western companies face in accessing resources in places like Iran and the Persian Gulf, which are off limits to foreign investors. Buying LNG from Australia is also cheaper for North Asian countries than shipping in gas supplies from the Middle East, Africa and the Caribbean.
However, the huge scale of investment in Australian resources carries several risks, such as worsening inflationary pressures by driving up wages of workers and prices of equipment. Safeguarding against delays and budget overruns has proved challenging so far, as exemplified by a US$885 million (900 million Australian dollar) cost blowout at Woodside Petroleum Ltd.'s flagship Pluto LNG project earlier this year.
Kirkland said he didn't see any significant bottlenecks at this point in time, although the availability of skilled labor was a concern as Wheatstone competes with Australia's other LNG developments and big mining-sector expansions.
"There is no doubt that the strength of the Australian dollar has increased the cost in U.S. dollar terms," said Kirkland, while acknowledging the 5% fall in the Australian dollar-U.S. dollar exchange rate since September 22. "We are presently estimating that about 50% of the cost of this project is in Australian dollars," he said.
Chevron proposes to build the Wheatstone facility in stages, with a maximum annual output capacity of 25 million metric tons of LNG. The foundation phase of the project near the town of Onslow will consist of two processing units, known as trains, with a combined capacity of 8.9 million tons of LNG a year, and a domestic gas plant.
"The benefits flowing from the Wheatstone project will be felt right across the country with the contribution it will make to jobs, government revenues, export incomes and spending on Australian goods and services," said Martin Ferguson, Australia's energy and resources minister.
San Ramon, CA-based Chevron will operate Wheatstone and own a 73.6% interest in the first stage of the project, with Apache Corp. /quotes/zigman/218137/quotes/nls/apa APA -1.01% , Kuwait Foreign Petroleum Exploration Co., and Royal Dutch Shell PLC /quotes/zigman/379012/quotes/nls/rds.b RDS.B +1.44% also holding significant stakes.
The project marks the continued drive by Chevron to focus on rapidly industrializing Asia and less on Europe and North America, where economic growth and energy demand is stagnating. Wheatstone is Chevron's second major Australian LNG project, after the A$43 billion Gorgon development, and the company holds over half its 150 trillion cubic feet of global gas reserves in the Asia-Pacific region.
However, gas exporters are vying for Asian customers at a time when countries like China are looking to replicate the shale gas boom in the U.S., where the unconventional fuel accounts for nearly a quarter of domestic gas output. China, which held its first auction of shale gas blocks in June, holds the world's largest technically recoverable shale gas reserves at 1,275 trillion cubic feet, according to the U.S. Energy Information Administration.
Chevron and its partners in Wheatstone have signed binding agreements to sell 3.1 million tons of LNG annually to Tokyo Electric Power Co. (9501.TO) and 800,000 tons of LNG a year to Kyushu Electric Power Co. (9508.TO), including an equity entitlement in the project, for up to 20 years.
Chevron and Tepco remain in talks over the possible purchase of an equity stake in Wheatstone, which would mean the venture has committed roughly 60% of first-phase output.
But an initial deal struck by the Wheatstone venture in July last year to sell 1.5 million tons of LNG annually to Korea Gas Corp. , known as Kogas, has expired.
Chevron was due to sell three-quarters of the LNG to Kogas, with the remaining volumes supplied by other Wheatstone shareholders. The deal also envisaged Kogas--the world's largest LNG importer by volume--buying a 5% equity stake in the Wheatstone processing plant and nearby gas fields.
"At this point in time there is a significant probability that we will not have a deal with Kogas," Kirkland said, without elaborating on why the two sides were unable to reach a binding agreement.
Chevron is now talking to "multiple parties" that may potentially buy gas from Wheatstone's foundation phase, he added.
Speaking on condition of anonymity, a Kogas official in charge of LNG imports said the Korean company had been unable to bridge differences with Chevron over the LNG price. Kogas later signed long-term supply deals from Australia with Shell and France's Total SA.
Hess Australia has awarded Expro a $6 million-plus contract for an offshore appraisal drilling campaign on Australia’s North West Shelf.
The semisubmersible Jack Bates drilling rig will perform this program, from 4Q 2011 through mid-2012.
Expro will deploy its well testing, subsea, slickline, fluids and sampling and wet gas meter capabilities. Expro’s well test technique involves flowing the well through a temporary completion and production system to measure flow parameters and to gather representative fluid samples for analysis.
These measurements serve to determine commercial viability, and assist planning of potential future completion and production facilities.
BP PLC's Indian unit is looking to buy an equity stake in liquefied natural gas terminals in the country as well as build LNG terminals in a joint venture with Reliance Industries Ltd. (500325.BY), its country head for India said September 6.
"As part of the joint venture deal with Reliance, we will look at importing gas at the terminal and then may mix it with domestic gas," Sashi Mukundan told reporters.
Last month, BP and Reliance Industries completed a $7.2 billion deal for oil and gas exploration, and a joint venture for marketing natural gas in India. BP got a 30% stake in Reliance's 21 oil and gas leases for $7.2 billion plus another $1.8 billion linked to exploration successes.
Steve Westwell, member of BP's executive management team, said BP is open to further investment opportunities in India's oil and gas sector.
"India is going to grow as one of the key markets for energy companies like us," Westwell said.
The Andhra Pradesh government has requested the Center to build a liquefied natural gas terminal on the east coast of the state to meet natural gas requirements of critical industrial sectors.
Chief Minister N Kiran Kumar Reddy wrote a letter to Union Petroleum Minister S Jaipal Reddy September 8 and said the terminal would help in industrial development in the region.
Sectors like power, fertilizers, steel, refineries as well as the city gas distribution network required LNG and Reliquefied Natural Gas, but were currently facing a short supply, he said.
While 12.97mmscmd of natural gas was required for the nine gas-based power projects in operation in the state, only 9.75 mmscmd was available from Reliance’s D-6 field and ONGC.
The only mechanism at present to supply LNG to willing customers in Andhra Pradesh is swapping of KG D-6 gas and RLNG being procured on the west-coast.
Britain's BG Group is eyeing stakes in ONGC's deepwater block and considering investment in an LNG terminal. But the company wants natural gas prices to be freed from government control.
Walter Simpson, the head of BG India, said his company was keen to pick up a stake in one of ONGC's oil and gas blocks in the Krishna Godavri Basin, which is adjacent to Reliance Industries' gas-rich D-6 block. ONGC plans to produce 25-30 million standard cubic meters per day of gas from the block by 2016-17.
"We had sent ONGC a proposal detailing our interest in picking up an equity stake in their Krishna-Godavari DWN 98/2 block about a year back. We are waiting for ONGC's response and continue to remain very keen to partner in the block," Simpson told ET.
India's exploration sector and the attractive market has lured oil major BP to invest $7.2 billion in a deal to acquire 30% in oil and gas blocks of Reliance Industries. A senior BP executive said on September 6 that gas pricing freedom was important for investors. Simpson shares his views. "Pricing freedom is imperative to encourage private sector involvement in natural gas production," he said.
The KG DWN 98/2 block is right next to Reliance's KG-D6 block. The region is India's most prolific gas basin and home to some of India's biggest natural gas discoveries.
ONGC had earlier said it planned to invest $7.7 billion to develop its gas field in the KG basin. Gas reserves of 3.42 trillion cubic feet (tcf) have been established in the KGDWN-98/2 block, of which 1.904 tcf is recoverable. Cairn India is already a 10% partner in the block.
State-run refiner Indian Oil Corp. is considering building a second terminal to import liquefied natural gas on the country's eastern coast as part of its upcoming Paradip refinery complex.
Indian energy companies are increasing gas imports to meet rising consumption as demand for natural gas outstrips supply.
Indian Oil's fuel requirements will rise sharply as more and more of its expanded capacity comes onstream, Refineries Director Rajkumar Ghosh told reporters September 27.
Mr. Ghosh said its refinery units currently burn liquid fuels like naphtha and need to switch over to cheaper alternatives like natural gas.
The Paradip refinery alone will need about 1.2 million metric tons of gas due to which Indian Oil is looking at building a 5 million ton LNG terminal, Mr. Ghosh said. "We're still thinking about it. Other companies may also join."
The country's largest refiner by capacity already has plans to build an LNG terminal at Ennore in a joint venture with the Tamil Nadu Industrial Development Corporation, an agency of the government in the southern state of Tamil Nadu.
The Ennore terminal is expected to have an initial capacity of 2.5 million tons a year, which can be expanded to 5 million tons a year, and cost $610 million (30 billion rupees-40 billion rupees).
"Directionally, we want to expand our gas business and LNG is an important segment," Chairman R.S. Butola told reporters after a shareholders' meeting.
He said the company plans to speed up the Ennore project. "We're going to award the front-end engineering and design, or FEED, contract. It might take six to eight months" to give the contract, he added.
"We're looking for a partner who can assure us that we'll be able to identify some sources of LNG ... we're talking to two-three companies," Mr. Butola said.
India's state-run refining and marketing companies expect their borrowing to rise in coming months as the government hasn't yet released any cash subsidy for the April-June quarter. The government gives the subsidy to share a part of their revenue losses from selling some fuels at state-set prices.
Mr. Goyal said Indian Oil has about 700 billion rupees of outstanding debt, which may rise due to a drop in the Indian rupee's value and high oil prices. He said the refiner plans to raise its borrowing limit by October to 1.1 trillion rupees from 800 billion rupees now.
Demand for liquefied natural gas in Japan has been rapidly rising for use in thermal power generation due to the energy gap created by the shutdown of nuclear power plants after the March 11 earthquake. In response to this circumstance, the Japanese government has established a policy to provide private corporations with financial support toward LNG exploration and development. The Ministry of Economy, Trade and Industry (METI) will sponsor about half of the necessary funds through Japan Oil, Gas and Metals National Corporation (JOGMEC).
METI predicts that the year-on-year demand for LNG in 2011 from all ten power companies across Japan will increase by 20% if nuclear power plant operations are not resumed as scheduled. The Ministry also estimates that LNG import will increase by approximately 17% within the same time frame.
International LNG supply has been increasing and prices have been decreasing as a result of the expansion of Qatar’s LNG production capacity and other efforts. Therefore, LNG required in Japan can be secured for the immediate future even if the LNG demand increases rapidly within the nation. Nevertheless, the LNG supply may become tight in a few years.
Participation in LNG exploration and development projects outside Japan is one of the means to achieve stable LNG supply. Because such effort requires a large amount of funds, risk mitigation for participating private corporations will be necessary.
Inpex Corp. has been engaged in constructing Naoetsu LNG Receiving Terminal in Joetsu City, Niigata Prefecture, (at the Naoetsu Port area) Japan seaside of Honshu Island, Japan since July 2009. Construction of various facilities is underway in Naoetsu LNG Receiving Terminal as scheduled toward to the operation start in 2014.
The current status of progress in construction of various facilities is shown below.
Facility Status of Progress:
As one of the important milestones, the lifting of dome-shaped roofs of the two LNG storage tanks was completed on September 13, 2011. Inpex will continue to implement the subsequent construction works without letting any accident take place.
History and planned schedule:
-- August 9, 2007: Announcement of Construction Plan
-- August 25, 2008: Final Investment Decision
-- July 7, 2009: The Ground-breaking Ceremony
-- July 8, 2009: Construction Start
--2013 (planned): Test Operation
--2014 (planned): Operation Start
Outline of Naoetsu LNG Receiving Terminal:
--Construction site: 12 Yachiho, Joetsu City, Niigata Prefecture (at the Naoetsu Port area) Japan (Approx. 25ha)
--Facilities: Berth, Two 180,000kl Storage Tanks, Vapolizer, Calorific Adjustment, etc.
Inpex is producing natural gas from Minami-Nagaoka Gas Field and other domestic Gas Field. After being processed, the natural gas is transported through a 1,400-km trunk pipeline network stretching across the Kanto and Koshinetsu regions, and is delivered to city gas companies and industrial customers along this pipeline network.
Natural gas demand has substantially increased over the recent years. Inpex understand that the demand of natural gas will continually grow due to the rise in other fuel prices, and also to the advantage of natural gas being eco-friendly. Therefore, in addition to extending the pipeline network, Inpex has introduced LNG from Shizuoka Gas Co., Ltd. and further decided to build Naoetsu LNG Receiving Terminal to bring in LNG from our major oversea LNG projects such Ichthys and Abadi as the feed gas. Thus Inpex will enhance the added value by establishing a gas supply chain through linkage between this network and Ichthys and Abadi.
Samsung Heavy Industries has successfully developed the industry's first membrane-type cargo hold for LNG tankers. With this, the company has finally tackled the last unsolved development initiative for the Korean shipbuilding industry, which was the cargo hold manufacturing technology for LNG tankers, completing a self-reliant Korean shipbuilding ecosystem.
SHI held a launch ceremony for SCA (Smart Containment-System Advanced), the cargo hold for LNG tankers, in London on September 6, and invited shippers and classification experts.
As this technology will enable cost savings of KRW 9 billion to KRW 10 billion per LNG tanker, it is expected that SHI will be able to increase its LNG shipbuilding competitiveness.
The cargo hold for LNG tankers is a tank containing LNG that is liquefied at -163 degrees, and is a critical part of an LNG tanker. In the past, all Korean shipbuilders manufacturing LNG tankers had to pay technology royalties, as a foreign company had the source technology.
With the aim of achieving self-reliant cargo hold manufacturing, Samsung Heavy Industries has conducted joint research with KAIST since 2007, with the master design and full design certified by major classification agencies, including LR and ABS.
In April 2011, the Company completed the mock-up certification and has undertaken phased preparation for the product launch by having tech briefings for the world's major oil companies, including BG, Chevron, CoP and Exxon Mobil.
The newly developed cargo hold for LNG tankers was built with tech upgrades, including improved membrane forms, newly developed secondary barrier materials and super-insulating materials, in order to improve stability, gas tightness and efficiency in transportation.
First, the wrinkled part of the membrane of the primary protective wall that is in direct contact with the LNG was improved to reduce sloshing and significantly enhance stability. Sloshing refers to fluctuations during operations, which may give shocks to tanks.
The secondary protective wall surrounding the primary wall was made of metallic materials, replacing the previous material of triplex that is made of glass fibers. The replacement of the material aimed to improve the gas tightness of the hold.
In addition, the super-insulating new material was applied to the insulation panels, preventing the evaporation of LNG and improving the efficiency of LNG transportation. In general, evaporative emissions created during the operation of LNG tankers are partially used as fuel, and the remaining emissions are self-propagated or disposed. The new material minimizes evaporative emissions of LNG.
CEO Roh In-Sik said, "If we apply this industry-first model to our LNG tankers, we will be able to improve our competitiveness in order receipts, as we no longer will have to pay high tech royalties."
Pipeline technology specialist, STATS Group, has completed a trunk line isolation project at the Petronas LNG complex in Bintulu, Malaysia.
The Petronas complex is one of the world's largest LNG production facilities on a single location, with an annual production of 23 million tonnes. The workscope was performed at the MNGL-Dua plant and was part of the Kumang Cluster onshore tie-in project which will supply the onshore facility with gas from the Kanowit CPP, located approximately 250km offshore Bintulu.
STATS were required to isolate 36" Trunk Lines 3 and 4 while the lines remained at an operating pressure on 69 barg. Two STATS remotely operated Tecno Plugs were utilized; one in each trunk line, during the project to isolate the pipeline upstream of the tie-in locations.
The Tecno Plugs were configured in a three module train to allow the tools to negotiate multiple bends as they were pigged approximately 80 meters to their set location.
The remote Tecno Plugs were tracked and accurately positioned using through-wall communication via an extremely low frequency (ELF) radio control system. The remote control system provided a high degree of flexibility and eliminated the need for tethers or specially modified pig-trap doors.
The remote Tecno Plugs were constantly monitored and remained stable and in location for approximately seven days while tie-in operations, which included close proximity hot work activities (welding), were completed. Finally, the plugs were unset and reverse pigged back to the receivers for demobilization.
STATS Group managing director, Pete Duguid, said: "This project marks a significant milestone for STATS as these are the first Tecno Plugs isolations carried out in Malaysia. There is great demand for STATS isolation technologies throughout South East Asia, which is a key market for our isolation technologies, and our future plans include establishing a permanent base in the region."
Hyundai Heavy Industries, the world's biggest shipbuilder, on September 19 won an US$400 million order to build two 155,000 cbm LNG carriers for Singapore-based BW Maritime.
Mr. Kim Oi-hyun, senior executive vice president and CEO of Hyundai Heavy and Mr. Clarence Lui, BW Maritime CFO & executive vice president, signed the contract that also includes an option to build two same class LNG ships.
These membrane-type LNG carriers, measuring 228 m in length, 44.2 m in width and 26 m in depth, are due for delivery in the second half of 2014 and the first half of 2015. The ships for liquefied natural gas feature the Dual Fuel Diesel Engine System (DFDE) which allows the ship to run both on oil fuel or natural gas.
Hyundai Heavy has been taking the lead in developing technologies for LNG carriers such as building Korea's first LNG ship in 1996, Korea's first DFDE-type LNG carriers in 2007, and the world's first new LNG-floating storage regasification unit in June 2011. Moreover, Hyundai Heavy has been developing a special welding system that can work on the thick aluminum plates used for the LNG tanks since 2010.
The Ulsan, South-Korea based company has won eight LNG carriers; including 2 LNG ships its affiliated company Hyundai Samho Heavy Industries received and two LNG-FSRU this year.
The commercial startup of Britain's first floating liquefied natural gas (FLNG) import terminal may be delayed until 2015 from 2014 owing to regulatory hold-ups, Norwegian developer Hoegh LNG said on September 5.
A final investment decision (FID) on the 3-6 billion cubic meter/year deepwater Port Meridian import terminal has been pushed back one year to the end of 2012, Hoegh LNG's Chief Executive Officer Sveinung Støhle told Reuters.
Delays to FID could delay start-up of the facility to 2015, Stohle said, although the company might be able to deploy one of its two floating storage and regasification units (FSRUs) now under construction for the project.
Two FSRUs under construction are due for delivery in 2013 and 2014 from South Korean shipbuilder Hyundai Heavy Industries.
"We have all the approvals, now we are focusing on getting customers on board in the next 6-12 months," Stohle said, referring to the UK project.
Falling production from ageing North Sea gas fields suggests UK import needs will continue increasing in the coming years, enticing investors to bankroll new terminals like Port Meridian, he said.
About 50 percent of the terminal's capacity will be sold on a medium-term basis, meaning between 3-5 years, while the majority of discussions are taking place with new market entrants eager to secure a foothold in physical trading.
Delays to start-up are not related to a pronounced slump in LNG trade in Europe, Stohle said.
Japan's shift away from nuclear power and towards gas since March has led a revival in appetite for LNG in Asia and created supply shortages in Europe.
Stohle said short-term fundamentals have not affected the long-term investment case for Port Meridian.
LNG accounts for roughly 29 percent of total UK supply, up from 17 percent in 2010, while domestic production has dropped from 49 percent last year to 41 percent in the year to date.
Britain has four operational import terminals, including the main Dragon and South Hook facilities in Milford Haven in Wales, Isle of Grain in Kent, and a smaller facility in Teesside.
The National LNG Terminal Project, which is a state enterprise, has declared the Socoin Company (Spain) as the winner of a tender for feasibility studies for a national project involving construction of a re-gasification liquefied natural gas terminal in Ukraine
Vladyslav Kaskiv, the chairman of the State Agency for Investment and Management of National Projects, made the announcement at a press conference.
According to Kaskiv, the winner of the tender is required to perform the feasibility studies within 112 days after signing a contract.
The cost of the feasibility studies is EUR 285,000.
Ramboll Oil and Gas (Denmark), Foster Wheeler Iberia (Spain), Socoin, Sener (Spain), and Technip Italy (Italy) participated in the second stage of the tender.
As Ukrainian News earlier reported, the National LNG Terminal Project invited tenders on July 6 for feasibility studies for construction of the re-gasification terminal.
Nine companies submitted tenders, but not all of them qualified for the second phase.
The potential suppliers of liquefied natural gas are considered countries in Central Africa, the Middle East, the Persian Gulf, and the South Caucasus.
Five potential locations for the facility had been identified as of September 16: around the Pivdennyi port, near the Pivdennyi oil terminal (both in the Odesa region), around the town of Ochakov, the coastal area of the Berezan Estuary (both in the Mykolaiv region), and an LNG terminal near Odesa.
The Iraqi Higher Energy Committee on September 5 ratified a liquefied natural gas agreement with Shell and Mitsubishi to upgrade energy facilities and to make use of gas in southern Iraq with a $13 billion (Dh45.5 billion) in investments over 25 years.
The agreement was awaiting final approval.
"The execution of the project will start in the first quarter of 2012 and will yield $30 billion in returns to the Iraqi government and save $40 billion for the Iraqi economy by turning from burning oil to the use of natural gas," said an official.
He said the joint venture will cost $13 billion, to be paid directly by Shell and Mitsubishi and indirectly by the Iraqi government over ten years, turning Iraq into a leading producer of liquefied gas in the region. Iraq will hold 51 per cent of the project, Shell 44 per cent and Mitubishi five per cent.
The project will help Iraq to export liquefied natural gas to world markets.
This will eliminate the need for gas imports from Iran and other countries and will help operate power stations at full capacity to provide southern Iraq with power.
This joint venture is being called Basra Gas, said a statement by the Ministry of Energy, which added that the production is especially targeted for the cities in the south.
The statement added that the venture will make use of 7,000 metric tonnes of LNG to produce 4,500 megawatts of electricity.
The joint venture will provide power for more than 20,000 houses.
"The project enables Iraq to make use of more than 700 million cubic feet per day of gas which is now being burnt in the southern oilfields of Rumaila, Zubair and West Qurna," it added.
Qatar's Rasgas is to shut down one of the world's biggest liquefied natural gas production units for maintenance next January, a company spokeswoman said on September 6.
She declined to say how long the outage, planned for the mid-winter peak demand period for most large gas consuming countries, would last.
"The planned routine maintenance on Train 7 will take place in January 2012," she said.
The plant, which can liquefy 7.8 million tonnes of natural gas per year (mtpa), started up in February 2010 and was built to supply North America, Europe and Asia.
On August 26, news that sister company Qatargas plans to stop three of its 7.8 mtpa plants in rolling maintenance planned for autumn caused the biggest rise in UK gas contracts since Japan's Fukushima nuclear crisis began in March on growing winter fuel fears among European buyers.
British benchmark front-season gas prices soared to new highs last week on fears the Qatargas work planned for autumn, when demand usually rises as temperatures in major LNG importing markets of north-west Europe and north-east Asia fall, could cut supply to Europe and increase Qatari LNG diversions to higher-paying Japan.
Gas producers typically carry out maintenance on their facilities during the summer for the northern hemisphere, where most of the world's gas is consumed and where leading importers Japan, Korea and Britain use it for heating in winter.
Despite low demand, widespread maintenance on Rasgas and Qatargas production facilities caused a big rally in UK gas prices in summer 2010 because Britain has become increasingly reliant on large quantities of Qatari LNG to offset its own declining production.
Rasgas, a joint venture between Qatar Petroleum and ExxonMobil, is one of two LNG producers in Qatar, the world's largest LNG exporter with the capacity to produce 77 million tonnes a year of gas.
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