Chris Smith
Senior Technology Editor
Warren R. True
Chief Technology Editor
As 2014 began, global LNG supply and demand remained largely in balance. Only two liquefaction plants came on stream last year, while several new or expanded terminals, especially in Asia, easily helped demand keep pace with supply.
A study of global LNG markets published by Barclays in February noted that start-up of Algeria's Skikda rebuild in March 2013 had not "translated into production growth for the country" and, citing shipping data from Waterborne Energy, that Angola's Luanda project, commissioned in June 2013, had delivered only 16 bcf. Both projects are described later.
The Atlantic Basin experienced steep production declines last year, mainly in Nigeria and Egypt, leading to production losses in the supply basin. In the Pacific Basin, however, expected growth of Australian production and a rebound in Malaysian volumes led to a 3.3% increase in LNG.
The Middle East, said Barclays, remained the main source of LNG production increases, mostly from more constant LNG flows from Yemen and an uptick in Qatari output.
Strong LNG consumption in Asia and Latin America, the study found, diverted many cargoes from European markets last year. In South Korea, strong LNG demand has resulted from six nuclear power plants remaining offline for much of 2013. At the same time, terminal expansions in 2012 at Dalian and Zhejiang in China pushed 2013 imports ahead.
Japan's LNG demand remained firm and even advanced slightly as it continued to wrestle with effects of nuclear power plants shutdown by the March 2011 earthquake and tsunami (OGJ Online, Apr. 8, 2011). In Latin America, Brazil's robust LNG demand slowed a bit in second-half 2013 as hydro reserves improved, said the Barclays study, while Mexico's LNG takes rose in second-half 2013.
The study expects tightness to continue this year, as only four LNG plants were expected to come online. In fact, one of those—Indonesia's Donggi Senoro—has been delayed yet again, to 2015. But in general, the study notes that whatever comes on line in 2014 will likely be late in the year and fall short of full production capacity.
What's happening, where, when
What follows is a roundup of developments in both supply and demand during 2013 and into 2014.
Australia, China
As 2014 began, FACTS Global Energy (FGE), Honolulu, painted a sobering picture of LNG in Australia, present and immediate future.
The unprecedented activity in LNG investment there during 2009-12 was "buoyed by an optimistic view of the market along with a healthy dose of euphoria." That has been replaced, FGE said, by "much more cautious and conservative consideration for LNG developments, plus just a dash of pessimism."
On the supply side, the picture is clouded by the "strength of the Australian dollar; high labor and materials costs; environmental regulation compliance and retrospective changes in requirements; private, heritage, and indigenous land rights; poor reserve conversion and well productivity; public opposition; industrial relations and productivity issues; taxation changes; and resource nationalism."
On the demand side, said the consultant, "global LNG buyers possess options for potential supplies from the US, Canada, East Africa, and Russia, after a buying spree over recent years [that] filled their portfolio requirements for Australian LNG."
In addition, the immediate outlook for oil prices is "less bullish," and owners of large Australian gas resources have become "more prudent."
Newly proposed LNG projects have been replaced by "cancellations or postponements, major development concept changes, less enthusiasm for brownfield expansions for projects being built, and large equity disposals."
FGE cited the latest twists in Browse LNG as evidence of recent changes in sentiment and "possibly a model for the future direction [of] Australian LNG."
Earlier this year, Woodside Energy Ltd. said it would not process gas destined for Browse LNG through the James Price Point onshore site, as it had planned and which Western Australia's state government had supported (OGJ Online, Apr. 12, 2013).
FGE said that, after spending $2 billion on studies to advance a plant, Woodside and JV partners—Royal Dutch Shell, BP, a Mitsubishi-Mitsui JV, and PetroChina—decided instead to look at monetizing their Browse basin gas reserves through floating LNG (FLNG). PetroChina is a unit of China National Petroleum Corp. (CNPC).
Woodside had concluded that the total cost for the 12 million tonnes/year (tpy), land-based LNG plant had reached $80 billion, making that option uneconomic.
Woodside will proceed with an FLNG scheme to develop the three Browse gas fields Torosa, Brecknock, and Calliance, which lie off Western Australia about 264 miles north of Broome. The company said the concept will use Royal Dutch Shell PLC's FLNG technology.
Browse participants include Woodside as operator, Shell Development (Australia) Pty. Ltd., BP Developments Australia Pty. Ltd., Japan Australia LNG (MIMI Browse) Pty. Ltd., and PetroChina International Investment (Australia) Pty. (OGJ Online, Aug. 21, 2013).
In another FLNG-based development, GDF Suez expects first gas shipments from its Bonaparte floating LNG plant off northern Australia in 2019. GDF Suez holds 60% of the project with Santos holding the remaining share.
Front-end engineering is under way; no final investment decision is expected before mid next year. Bonaparte is designed to produce 2.4 million tpy from Petrel, Tern, and Frigate gas fields.
And in fourth-quarter 2013, the Australian government approved another proposed FLNG project, this time for Scarborough gas field off Western Australia, owned equally by ExxonMobil Corp. and BHP Billiton.
As proposed, that FLNG plant would produce 6-7 million tpy from five trains. The 1,624-ft vessel would be permanently moored on Scarborough.
ExxonMobil has said offshore installation and commissioning would take place in 2019-20; production could start in 2020-21 (OGJ Online, Nov. 12, 2013).
Finally among projects on Australia's western side, Royal Dutch Shell earlier this year agreed to sell its 8% equity interest in the Wheatstone-Iago joint venture (JV) and 6.4% interest in the 8.9-million-tpy Wheatstone LNG project in Western Australia for nearly $1.14 billion to Kuwait Foreign Petroleum Exploration Co. (Kufpec).
The acquisition nearly doubled Kufpec's interest in the $29 billion (Aus.) LNG project to 13.4% from 7%. It will now hold the second-largest stake behind project operator Chevron Australia, which has 64.1%. Other interest holders are Apache Energy 13%, Tokyo Electric Power Co. 8%, and Kyushu Electric Power Co. 1.46% (OGJ Online, Jan. 20, 2014).
Turning to projects along Australia's eastern coast and centered on Gladstone, owners of the Santos GLNG project reported only a few weeks ago that it had reached 75% completion and was on track for first shipment from Gladstone Harbor in Queensland in 2015. Santos GLNG is a JV among Santos, Petroliam Nasional Bhd. (Petronas), Total, and Korea Gas Corp. (Kogas).
The project reported that, on Curtis Island, a 2.5-mile pipeline under Gladstone Harbor had reached the island following 10 months of tunneling. The segment is part of an overall 261-mile pipeline due to be completed around mid-year.
In addition, the first train was nearing completion and the second train was under construction.
Also on Curtis Island, operator BG Group announced in December first gas had moved more than 335 miles from the Surat basin coalseam gas fields to the island where commissioning of the first of two trains of Queensland Curtis LNG (QCLNG) was expected early this year.
Earlier last year, China National Offshore Oil Corp. (CNOOC) took a 50% interest in Train 1 of QCLNG.
Under a separate agreement and from its own global sources, BG is to supply CNOOC with another 5 million tpy of LNG for 20 years beginning in 2015.
The agreement included CNOOC's receiving a 20% interest in reserves and resources of some of BG's permits in the Walloon Fairway region of the Surat basin, taking its share there to 25%. In addition CNOOC gets a 25% equity in other BG permits in the Bowen and Surat basins.
CNOOC also retains the option to participate up to 25% in one of the possible expansion LNG trains at QCLNG on Curtis Island (OGJ Online, Nov. 12, 2013).
In other developments on the east coast, Australia Pacific LNG is building an LNG plant that it said last year was more than 50% complete. Completion is on track for mid-2015.
Along with other LNG projects, this JV of Origin Energy 37.5%, ConocoPhillips 37.5%, and China Petroleum & Chemical Corp. (Sinopec) 25% will be supplied by coalbed methane from fields in the Surat and Bowen basins. It plans two, 4.5-million-tpy trains (OGJ Online, Oct. 28, 2013).
In China in July last year, Sinopec began building its Tianjin LNG import terminal. Work is progressing in two phases to install a total of 10 million tpy.
Each phase is to include three 160,000-cu-m LNG tanks. The first phase includes a carrier berth, LNG receiving equipment, and a 435-mile pipeline able to send out 4 billion cu m/year (about 1.4 tcf).
At Qingdao, in Shandong Province, Sinopec will finish by yearend its first LNG import terminal. After completion and start-up of its 3-million-tpy first phase, a second phase will expand capacity to 5 million tpy with possible later expansion to 10 million tpy.
Cargoes are expected from Papua New Guinea and from Australia Pacific LNG's Queensland project, described earlier, by mid-2015.
CNOOC last year laid out plans for five LNG terminals in operation by 2015 with total import capacity of nearly 40 million tpy.
One of the new terminals is China's first floating LNG terminal at Tianjin. It received its first cargo in January, 30,000 tonnes aboard the Gaslog Savannah from Atlantic LNG in Trinidad and Tobago.
The new, $539-million FLNG terminal can receive up to 2.2 million tpy. The project includes a berth and two 30,000-cu-m storage tanks. A second, land-based phase could expand receiving capacity to as much as 6 million tpy.
The floating terminal was built on the base of GDF Suez's 145,000-cu-m Cape Ann floating storage and regasification unit (FSRU) under a 5-year charter.
The Tianjin terminal is the company's second import terminal brought online last year. In late October, CNOOC commissioned the 3.7-million-tpy Zhuhai terminal at Gaolan in the southern Guangdong Province with a cargo from Qatargas aboard the 216,000-cu-m Al Gattara.
The Fujian terminal can handle up to 3 million tpy in its first phase and cost $1.1 billion, said area press reports. It could accommodate 260,000-cu-m tankers and has three 160,000-cu-m storage tanks.
Planned terminals over the next 2-3 years include a 3-million-tpy project on Hainan Island, a 2-million-tpy Yuedong terminal in Jieyang in southern Guangdong Province, and a 4-million-tpy Diefu terminal in Shenzhen in Guangdong.
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CNOOC is also considering expanding the newly opened Zhuhai terminal by 7 million tpy.
In December last year, PetroChina's new Tangshan terminal in China's Hebei Province received its first cargo in preparation for full commissioning early this year.
Platts reported that the 216,000-cu-m Al Gharrafa arrived at the Caofeidian port in Tangshan in November with a cargo from Ras Laffan. The new terminal's first phase can accommodate up to 3.5 million tpy; its second phase will take capacity to 10 million tpy.
Also last month, Platts reported that privately owned Guanghui Energy had started building an LNG terminal in Qidong, in eastern Jiangsu Province.
Start-up was planned for late 2016 or early 2017. Phase 1 envisions 600,000 tpy, ramping up to 3 million tpy by 2019 if market conditions warrant.
Other Asia
Singapore LNG officially commenced operations at its $1.7 billion, Jurong Island site, accepting the first cargo in early May 2013 from BG Group.
The terminal had an initial throughput capacity of 3.5 million tpy with two tanks but expanded by yearend to 6 million tpy when a third tank, additional jetties, and regasification equipment were completed.
In October 2012, SLNG announced plans for a fourth tank and associated regasification, raising throughput capacity to 9 million tpy.
In India in August last year, Petronet LNG finally started up its 5-million-tpy Kochi LNG terminal on the country's western coast after several delays (OGJ, Apr. 1, 2013, p. 90). The 125,000-cu-m Wilenergy carrying a cargo from RasGas landed in heavy weather in August.
Kochi is the fourth LNG terminal to be commissioned in India, the second by Petronet, which also operates the 10-million-tpy Dahej terminal in Gujarat state.
In May of last year, Shell completed expanding the Hazira terminal, also in Gujarat on India's western coast, to 5 million tpy from 3.6 million tpy. Operator Hazira LNG is a JV between Shell 76% and Total 26%.
The Hazira terminal has been greatly underutilized, however, and was immediately shut down upon completion of the expansion.
But Shell is moving ahead with another terminal, this one at Kakinada in India's Andhra Pradesh state in what would be the first FLNG project on the eastern coast. Planned capacity is 5 million tpy with an option to double that if warranted by gas demand in the region.
In Pakistan in January this year, Sui Southern Gas approved construction of Engro Corp.'s Elengy regasification terminal at Port Qasim. Following a memorandum of understanding in February 2012, Pakistan is in negotiations with Qatar to import 3.5 million tpy, which could begin as early as fourth-quarter this year.
In Indonesia, start-up of the 2.1-million-tpy Donggi-Senoro LNG project has been delayed to March 2015 from 2014, according to shareholder Mitsubishi Corp. Other shareholders include Kogas, Indonesia's Medco Energi Internasional, and Indonesia's state-owned PT Pertamina.
In Japan last month, the government issued a final draft of a new medium-to-long-term energy program, the first since the 2011 earthquake and tsunami. The draft envisions nuclear power as a baseload source but looks for renewable energy sources (hydro) and thermal power plants to dominate.
Japan is the world's largest importer of LNG, and in an analysis Barclays stated thermal generation will likely drop crude oil and fuel oil before there are any reductions in natural gas-fired generation.
In early December of last year, Inpex Corp. began operations at its Naoetsu LNG terminal in Joetsu City, Japan. The terminal includes two aboveground LNG tanks and a berth for unloading a 210,000-cu-m LNG tanker. It can receive and regasify 1.5 million tpy of LNG (OGJ Online, Dec. 10, 2013).
Inpex reached final investment decision (FID) to construct the terminal in 2008 and began construction in 2009. Commissioning work began in August for full-scale commercial operations, which had been scheduled for January 2014 (OGJ Online, Aug. 27, 2013).
In Malaysia earlier this year, state oil company Petronas reached FID on its second floating LNG project. The unit—PFLNG2—will be moored at Rotan gas field in deepwater Block H, offshore Sabah, and produce 1.5 million tpy of LNG (OGJ Online, Feb. 5, 2007). It is to be ready for start-up by early 2018, said the company's announcement (OGJ Online, Feb. 14, 2014).
Last year in Papua New Guinea, ExxonMobil commissioned its LNG plant near Port Moresby for first production in the second half of this year.
The plant will have capacity to produce 6.9 million tpy of LNG. The project is owned by ExxonMobil 33.2%, Oil Search 29%, the PNG government's National Petroleum Co. of PNG 16.8%, Santos 13.5%, JX Nippon Oil and Energy 4.7%, and local landowner company MRDC 2.8%.
In Thailand, PTT LNG, a subsidiary of state-owned PTT, decided last year to move ahead with plans to double capacity at its 5-million-tpy Map Tha Phut import terminal. Expanding the terminal includes building a new jetty, processing, and regasification, and storage tanks. Last year, the government approved investment of $698 million for the expansion.
The existing terminal, in Thailand's eastern Map Tha Phut Industrial Estate in Rayong Province, started operating in September 2011.
In Russia's Far East in December, Gazprom and Shell agreed to expand the two-train, 4.8-million-tpy Sakhalin 2 LNG plant by 5 million tpy to enter service as early as 2017-18.
Sakhalin 2 draws gas from Piltun-Astokhskoye oil field and Lunskoye gas field, with combined recoverable gas reserves estimated at 500 billion cu m. The project's shareholders are Gazprom 50% (plus one share), Shell 27.5% (minus one share), Mitsui 12.5%, and Mitsubishi 10%.
Gazprom last year also reached FID on the Vladivostok LNG plant. It would use three 5-million-tpy trains on Lomonosov Peninsula, the first coming on line in 2018. A JV of Itochu 32.5%, Japex 32.5%, Marubeni 20%, Inpex 10%, and Itochu Oil Exploration 5% joined Gazprom in the investment study.
Africa
Emerging as major competition for Australian LNG projects in Asian markets are the gas fields off East Africa. In a report in late 2012, London-based Center for Global Energy Studies noted that a steady stream of drilling had transformed Mozambique and Tanzania into future LNG exporters.
The two nations, said CGES, were at a point of confluence for numerous important developments in the energy industry. "These include the rise of Africa as an energy hub, the advancement of deepwater exploration and production as a result of higher oil prices, and the rising prominence of LNG as a rival to oil," said the study.
Major upstream players in the region have included Anadarko, ENI, Ophir, BG Group, and Statoil. "All are sitting atop gas reserves of a suitable size to be monetized by LNG development," it said.
Early last year, Anadarko Corp. awarded Bechtel a front-end engineering and design contract for an LNG plant in Mozambique. The contract was for Phase 1 of the shore-based plant to be built in Cabo Delgado Province in the northeast of the country.
Bechtel said in an announcement that the design would feature a "multi-train liquefaction plant" with nameplate capacity of 5 million tpy, expandable to 50 million tpy. Initial sales were planned for 2018 (OGJ Online, Apr. 26, 2013).
Later, in March 2013, Reuters reported that Statoil and BG Group were planning a two-train, $10 billion East African LNG plant to liquefy natural gas from a discovery of 4-6 tcf in the Indian Ocean off Tanzania. FID on the project, however, was not expected before 2016.
About the same time, PetroChina agreed to purchase part of Eni's gas field in Area 4 off Mozambique for $4.2 billion (OGJ Online, Mar. 14, 2013).
PetroChina bought 28.57% of Eni East Africa's 70% interest in Area 4. With the purchase, CNPC indirectly acquired a 20% stake in Area 4, while Eni remained the owner of 50%.
Remaining shares in Area 4 are held by Kogas and Galp Energía, each with 10%, while Mozambique's state ENH has 10% carried through the exploration phase (OGJ Online, Feb. 26, 2013).
At the time, Eni said it expected to take FID on the Mozambique project in 2014.
In North Africa last year, Algerian state company Sonatrach commissioned the new 4.5-million-tpy LNG production train at Skikda on the Mediterranean coast about 300 miles east of Algiers.
The train replaces a 3.7-million-tpy complex destroyed in an explosion in 2004 (OGJ, Apr. 1, 2013, p. 90; OGJ Online, Jan. 27, 2004).
And in West Africa in July last year, Angola LNG delivered its first cargo, to Brazil aboard SS Sonangol Sambizanga. The 160,000-cu-m shipment unloaded at Petrobras's regas terminal in Guanabara Bay, Rio de Janeiro.
At full production, the $10 billion plant at Soyo, Angola, can supply 5.2 million tpy of LNG, plus propane, butane, and condensate, according to an Angola LNG announcement at the time.
Angola LNG is a partnership among Sonangol 22.8%, Chevron 36.4%, BP 13.6%, ENI 13.6%, and Total 13.6%. The project, according to the company, seeks to reduce flaring and environmental pollution by gathering associated gas from Angola's offshore oil fields.
Canada
British Columbia has proposed a two-tiered tax regime for LNG projects in the province. The first tier would tax operators at a 1.5% rate on net income once commercial operations start, with the second tier kicking in at 7% once the operator has fully recouped its capital investment.
Legislation putting the tax system in place will occur over the balance of this year and into 2015. British Columbia Prime Minister Christy Clark has said the province would start collecting LNG revenues by 2017.
Kitimat LNG partner Chevron Canada Ltd. in January awarded an engineering, procurement, and construction (EPC) contract to a JV of Fluor and JGC Corp. Project scope includes completing the existing front-end engineering and design (FEED) package and detailed engineering and procurement for the initial phases of the project.
Apache Canada Ltd. is the other equal-interest partner with Chevron for the Bish Cove, BC, project. Apache, however, is looking to sell a portion of its stake as part of ongoing cost-cutting. Chevron Canada acquired its 50% interest in Kitimat LNG last year along with half interests in the proposed Pacific Trail Pipeline and in 644,000 acres in the Horn River and Liard basins in BC (OGJ Online, July 10, 2013; OGJ, Jan. 7, 2013, p. 42).
The two-train Kitimat project targets a 2016 start-up (Table 1). Canada's National Energy Board (NEB) license allows export of 10 million tpy.
In March 2013, Japan Petroleum Exploration Co. (Japex) bought 10% of Pacific Northwest LNG and associated North Montney shale gas project from operator Petronas. Japex would receive 1.2 million tpy from the 12-million-tpy terminal on Lelu Island, Prince Rupert, BC.
Petronas in February this year sold Indian Oil Corp. 10% of the project, with Bloomberg reporting another 15% sale likely to a second Asian buyer, bringing Petronas's ownership down to 62%, with Japex holding 10%, and Petroleum Brunei 3%. Press reports at the time also had Petronas talking to other buyers in an effort to bring down its total interest to 50%.
The NEB approved a 25-year export license for this project to ship as much as 19.68 million tpy. Petronas plans to reach FID by the end of this year and start operations by yearend 2018. It submitted its environmental assessment applications in February.
LNG Canada—a consortium of Shell, Kogas, Mitsubishi Corp., and PetroChina International—received in February 2013 NEB approval to export as much as 24 million tpy for 25 years. Its plant would be in Kitimat, with start-up expected in 2020. An environmental review of the project is under way. The company in February secured wharf space at Kitimat from Rio Tinto on property once used by Eurocan.
Under a 50:50 plan by oil refiner Idemitsu and gas pipeline operator AltaGas, the two may build an LNG export terminal near Kitimat, possibly starting LNG exports mainly to Japan as early as 2017. The venture, Triton LNG, also plans to develop an LPG export business.
Aurora LNG, a JV of Nexen (a division of CNOOC), Inpex, and JGC, in November last year acquired exclusive rights to almost 1,900 acres of BC government land and deepwater access at Grassy Point, 18 miles north of Prince Rupert, for an LNG export plant. Aurora must apply to NEB for an LNG export permit and is conducting a feasibility study, environmental impact assessment, and consultations. CNOOC acquired Nexen in 2012 to improve its access to Western Canadian shale gas.
An Imperial Oil-ExxonMobil partnership and Woodside Petroleum have also expressed interest in developing separate LNG plants at Grassy Point. WCC LNG Ltd., the ExxonMobil-Imperial JV, in December last year received NEB permission to export up to 30 million tpy under a 25-year license. The JV owns 340,000 acres in the Horn River basin in northeastern BC. WCC expects initial exports of 5 million tpy in 2021, with full rates reached by 2025.
Woodside and the BC government agreed to give Woodside exclusive rights to negotiate a long-term lease with the federal government to build an LNG plant on the southern end of Grassy Point near Prince Rupert.
Pacific Oil and Gas Group in December received NEB permission as Woodfibre LNG Export to build an LNG export plant in Woodfibre, BC. The plant would have 2.1 million tpy capacity and received NEB authorization to export that amount for 25 years. The company expects first LNG by late 2017. Target markets include Japan, China, and South Korea. Pacific Energy, a Pacific Oil and Gas Group affiliate, would supply the natural gas.
The NEB at the same time approved a 25-year natural gas export license to BG Group's Prince Rupert LNG Exports Ltd. (21.6 million tpy). British Columbia's new tax proposal, however, has caused BG to delay FID to 2017 while it evaluates the proposal's implications, according to local media.
Kitsault Energy Ltd. applied for a 20-million-tpy export permit for a plant it would build at Kitsault, BC, a privately owned abandoned mining town on the province's northern coast. The company is still working to secure gas supply agreements.
On Canada's Atlantic Coast, Pieridae Energy (Canada) Ltd. has proposed construction of a 10-million-tpy liquefaction plant in Goldsboro, NS. The site is adjacent to the Maritimes & Northeast Pipeline and would include 690,000 cu m of LNG storage. Local press reported review of the project as under way and, pending regulatory approvals, that construction on Goldsboro LNG could begin next year with operations targeted for 2019.
US
Australia's Liquefied Natural Gas Ltd. signed a binding pipeline capacity agreement in January with Kinder Morgan Louisiana Pipeline (KMLP) for its proposed Magnolia LNG export project in Lake Charles, La., securing sufficient firm gas transportation for the plant's full 8-million-tpy capacity. Magnolia will use four 2-million-tpy trains.
The KMLP pipeline crosses the project site. In addition to the on site Kinder Morgan pipeline, Magnolia can access supply from 11 other gas transmission corridors, including three pipelines it describes as underutilized within 3 miles.
LNG Ltd. hopes to gain full regulatory approval by 2015 to reach FID by the middle of that year and meet a mid-2018 start date. The company in February named SKEC Group preferred EPC contractor.
Corpus Christi Liquefaction LLC, a unit of Cheniere Energy Inc., Houston, last year awarded an EPC contract for LNG trains and related facilities to Bechtel. Yet to be approved by the US Federal Energy Regulatory Commission (FERC), the three-train, 13.5-million-tpy Corpus Christi project would be built in two stages. Work under the contract is to begin this year, subject to Corpus Christi Liquefaction's reaching FID; operation of the first LNG train would begin in 2018.
The Stage 1 EPC contract includes two LNG trains, two tanks, one complete berth, and a second partial berth. Stage 2 EPC contract includes one LNG train, one additional tank, and completion of the second berth, according to the Bechtel announcement.
Cheniere's first LNG sale and purchase agreement for the Corpus Christi project was with Pertamina for about 0.8 million tpy.
Cheniere also applied to FERC last year for authorization to expand its Sabine Pass LNG export terminal in Louisiana. The application requested authorization to add two 1.4-bcfd liquefaction trains to the four being built at the Sabine Pass site under an export permit from the US Department of Energy (DOE) and a FERC construction permit (OGJ Online, Dec. 18, 2013).
The company plans to start operations at Train 5 by yearend 2018, with Train 6 coming online whenever commercially feasible. The original Sabine Pass export project is one of only five Lower-48 projects approved by DOE to ship LNG to non-free trade agreement (FTA) countries (Table 2). In February, FERC approved Sabine Pass LNG increasing throughput to its original four trains to 2.76 bcfd.
DOE in November last year conditionally approved 0.4 bcfd more non-FTA exports from Freeport LNG, bringing its total permitted volumes to 1.8 bcfd (OGJ Online, Nov. 15, 2013). Freeport signed liquefaction tolling agreements with Chubu Electric and Osaka Gas for the first of this plant's three trains, with BP Energy Co. for the second, and in September with Toshiba Corp and SK E&S for the third.
FERC in March issued a draft environmental impact statement citing "temporary and short-term" effects of the Freeport export project, which could be adequately mitigated to allow its approval.
In Louisiana, Lake Charles LLC, a JV of Southern Union Co. and BG Group, was licensed to export 2 bcfd (OGJ Online, Aug. 8, 2013). In Maryland, Cove Point's conditional approval to export up to 0.77 bcfd pushed overall non-FTA export approvals to 6.77 bcfd as of November.
This total grew in February this year when DOE approved Sempra's Cameron LNG plant in Hackberry, La., to export 1.7 bcfd to non-FTA countries. Sempra plans to have the plant in operation by 2017 (OGJ Online, Feb. 11, 2014).
El Paso Pipeline Partners LP announced last year that Shell US Gas & Power LLC, a Royal Dutch Shell subsidiary, had given notice to Elba Liquefaction Co. LLC to move ahead on Phase 2 of the jointly owned liquefaction project at Southern LNG Co.'s Elba Island LNG terminal, near Savannah, Ga.
Phase 2 will add 0.5-1.0 million tpy of capacity at an estimated $500 million at the maximum volume, said the announcement. The planned six trains of Phase 1 will provide about 2.4 million tpy of export capacity at start-up in late 2016 or early 2017 (OGJ Online, Aug. 16, 2013).
Phase 2 will add two trains and start up in 2017-18. If the maximum volume for Phase 2 is elected, said the announcement, the Elba liquefaction project will have total capacity of about 2.5 million tpy of LNG.
The project remains under review by FERC.
Trunkline LNG Export LLC awarded Technip the FEED contract for potential expansion of its three-train, 15-million-tpy plant planned for the site of Trunline's existing LNG import terminal in Lake Charles, La. The project includes a three-train, 15-million-tpy LNG liquefaction plant.
Trunkline LNG, a JV of Energy Transfer and BG Group, expected the study to be completed by Apr. 1.
Elsewhere, ExxonMobil, BP , ConocoPhillips, and TransCanada last year selected the Nikiski area on the Kenai Peninsula as the lead site for the proposed Alaska LNG project's liquefaction plant and terminal.
More than 20 locations were evaluated based on conditions related to the environment, socioeconomics, cost, and other project and technical issues (OGJ Online, Oct. 7, 2013; Jan. 27, 2014).
The companies are continuing to refine the agreed project, which includes a gas-treatment plant on the North Slope, an 800-mile, 42-in. OD pipeline with up to eight compression stations and at least five off-take points for in-state gas delivery, and a liquefaction plant.
More detailed engineering and design work is under way, consistent with previously released plan phases.
Alaska LNG plans to reach FID in 2018-19 and will file for an export license later this year to meet that timeframe. In February, Alaska's Senate Resources Committee passed Bill 138 authorizing the project with the bill subsequently moving to the Senate Finance Committee.
ConocoPhillips also filed applications for 2-year authorizations with DOE to resume seasonal LNG exports from its mothballed Kenai Peninsula LNG plant during non-winter periods. Exports would total about 20 bcf/year.
Panama Canal
Delays to the Panama Canal expansion are likely to create only limited disruptions to global LNG trade, according to a report in February by Wood Mackenzie. Delays of 6-12 months would fall into this limited-disruption category, but further delays could pose problems as new non-FTA US export projects begin to come online.
Wood Mackenzie noted in particular that a delay until early 2016 would affect the first LNG exports from Sabine Pass, imposing higher shipping costs as vessels would have to round the Cape of Good Hope to reach Asia. The longer routing would also tighten the LNG shipping market.
Expected differentials between US and Asian gas prices, however, and expansion of the shipping fleet between now and 2016 would help mitigate these effects, Wood Mackenzie said. Work stopped for 2 weeks due to disputes with the contractor regarding who was responsible for $1.6 billion in cost overruns. Work on the third set of locks resumed in February.
LNG does not currently pass through the Panama Canal because the carriers are too wide. The expansion will allow passage to all but the very largest LNG carriers. The Panama Canal Authority said in February that the expansion would enter commercial service January 2016, assuming no more work stoppages.
South America
Brazil and Uruguay plan to expand their LNG import infrastructure, while Colombia and Peru look to boost exports.
• Brazil. Brazil's state-owned Petroleo Brasileiro SA (Petrobras) in January started its third LNG import terminal. The Petrobras LNG regasification terminal in Bahia has a 14-million-cu-m/day (cmd) capacity, bringing Brazil's total regasification capacity to 41 million cmd. The country's other two import terminals are in Pecem, Ceara state (7 million cmd), and Guanabara Bay, Rio de Janeiro state (20 million cmd).
• Colombia. Pacific Rubiales Energy and Exmar will begin operating a 70-MMcfd export gas liquefaction plant in Tolu on Colombia's Caribbean Coast by early 2015, LNG World News reported. China is building the FSRU for delivery late this year. The vessel, Caribbean FLNG, will have 16,100 cu m of LNG storage. Exmar is paying for the vessel while Pacific Rubiales picks up the cost of an 18-in. OD, 90-km pipeline connecting it to onshore gas supply from La Cresciente field in Sucre province.
Pacific Rubiales has a 15-year agreement in place to supply Exmar with gas FOB Colombia for delivery to Caribbean customers.
• Peru. Royal Dutch Shell in January acquired Repsol SA's non-North American LNG portfolio, including Peru LNG Co.'s 4.45 million tpy of liquefaction capacity (OGJ Online, Feb. 26, 2013).
• Uruguay. GDF Suez and Marubeni in February chartered the world's largest FSRU to supply LNG to Uruguay from 4 km off Montevideo, Platts reported. The 1,132-ft ship will have 263,000 cu m of LNG storage (160.17 million cu m natural gas) and as much as 10 million cmd of natural gas sendout capacity, expandable to 15 million cmd.
The terminal, to be delivered in late 2016, would be able to receive LNG tankers up to 218,000-cu-m capacity. GDF Suez's regasification vessel Neptune will provide LNG offtake starting next year until the terminal begins operations.
Europe
While Russia sees LNG exports as a path to potential new natural gas markets, the rest of Europe continues to build regasification terminals in an effort to reduce its dependence on Russian supplies.
• Russia. Owners last year reached FID on Yamal LNG, with the 16.5-million-tpy liquefaction plant to be built on the Yamal Peninsula on the Kara Sea and first-train start-up set for 2017.
The $27 billion project consists of developing giant onshore South Tambey gas and condensate field on the peninsula, three 5.5-million-tpy trains, LNG storage tanks, and port infrastructure at Sabetta. As many as 16 icebreaking LNG carriers will be commissioned to handle international trade via the Arctic Ocean.
Operator Yamal LNG JSC is owned by Total 20% and Novatek 80%. In September, Novatek and CNPC agreed to CNPC's acquiring 20% of the project. A consortium of France's Technip and Japan's JGC will perform engineering, procurement, supply, construction, and commissioning of the plant (OGJ Online, Apr. 5, 2013). The consortium selected Air Products to supply three cryogenic heat exchangers. Vinci will build four 160,000-cu-m storage tanks.
• Poland. Polskie LNG's 5 billion cu m/year terminal at Swinoujscie continues to fall behind in its development due to financial problems at contractor PBG. Polskie originally planned to have the terminal operating in time to receive contract shipments of 1.5 billion cu m/year from Qatargas as early as July, but this now looks likely to occur later in the year. The terminal was 75% complete as of February, Platts reported. Polskie is also considering adding a third train to increase capacity to 7.5 billion cu m/year.
• Finland. Wartsila signed a contract with Manga LNG to build Finland's first LNG receiving terminal in Tornio. The terminal would supply the local steel mill as well as other regional industry and, eventually, bunkering for LNG-fuelled ships. Manga expects the terminal, including 30.4-billion-cu-m storage, to begin operations in 2017.
• Estonia, Latvia, Lithuania. Klaipedos Nafta in January received permits to begin building the embankment for the shore portion of a regasification terminal in Lithuania. The company expects to take delivery of the FSRU Independence by yearend for stationing off Klaipeda.
Latvia, however, has said that a Baltic LNG terminal should be its project. Finland and Estonia, meanwhile, asked the European Commission to decide the location of a Baltic terminal, with the EC advising that the countries instead decide among themselves. The European Union could fund as much as 40% of a regional terminal's costs as long as it serves more than one country.
Estonia and Finland signed an agreement in February to build two LNG terminals on either side of the Gulf of Finland, linked by a pipeline. The respective terminal developers must turn in technical and commercial details to domestic regulators and the EC by the end of May.
• Italy. The long-delayed FRSU for the Italian port of Livorno started operations last year 12 miles offshore (OGJ Online, Aug. 29, 2013). The Toscana FSRU can vaporize 3.75 billion cu m/year of LNG and store up to 137,500 cu m. Shareholders are E.On Group 46.79%, Iren Group 46.79%, OLT Energy Toscana 3.73%, and Golar Offshore Toscana 2.69%.
Italy has two other operating LNG terminals. The 2.5-million-tpy onshore terminal at Panigaglia is owned and operated by GNL Italia and began operations in 1969. The world's only fixed offshore LNG terminal at Porto Levante can accommodate 5.8 million tpy. It is owned and operated by Adriatic LNG, a JV of ExxonMobil, Qatar Petroleum, and Edison.
The 5.8-million-tpy Porto Empedocle terminal in Sicily is under construction. Owned by Nuove Energie, a JV of Enel and the Siderurgica Investimenti Group, the terminal targets commissioning and start-up in 2016.
Smart Gas Monfalcone, a 12-company consortium, plans to build a regasification terminal in northeastern Italy capable of importing 800 million cu m/year of LNG. The consortium expects the terminal to begin operations in 2018
• Cyprus. The Republic of Cyprus and Total E&P Cyprus BV in November 2013 signed a memorandum of understanding (MOU) furthering prospects for LNG exports from the island (OGJ Online, Nov. 8, 2013).
This follows the award in February to Total of production-sharing contracts for Blocks 10 and 11 in Cyprus's Exclusive Economic Zone (OGJ Online, Feb. 6, 2013).
The MOU, said the joint announcement, "records the support" of Total for monetization of potential natural gas reserves in the area through a "variety of options giving priority" to liquefaction and LNG export to European and Asian markets. The two parties will cooperate on the feasibility of an onshore LNG plant to be built at Vasilikos, Cyprus.
In June 2012, the Republic of Cyprus decided to begin work toward the LNG plant at Vasilikos, which will have initial export capacity of 5 million tpy, expandable to 15 million tpy.
Cyprus is also preparing an MOU with Eni to include it in the Vasilikos plant plans, according to Platts. Eni and Kogas won Blocks 2, 3, and 9. The country is also negotiating with Noble Energy regarding the LNG plant, which is not expected to begin operations until at least 2022. China has expressed interest in participating in the project.
CorrectionTable 2 in the article entitled "Product pipeline completions lead planned construction lower" by Christopher E. Smith (OGJ, Feb. 3, 2014, p. 90) was mistitled. Its title should have read ‘Pipeline construction beyond 2014.' |