SPECIAL REPORT: Global LNG capacities rising to meet increasing demand

March 7, 2011
Taken together, 2010-11 may represent that point in the evolution of natural gas trade when gas comes into its own among hydrocarbon fuels.

The ExxonMobil Corp.-operated Golden Pass LNG terminal, on the Sabine Pass waterway near Port Arthur, Tex., received its first commissioning cargo in October 2010. The 15.6-million-tpy (peak) terminal is a joint venture of Qatar Petroleum International 70%, ExxonMobil 17.6%, and ConocoPhillips 12.4% (photo from ExxonMobil).

Warren R. True
Chief Technology Editor—LNG/Gas Processing

Taken together, 2010-11 may represent that point in the evolution of natural gas trade when gas comes into its own among hydrocarbon fuels.

With the advent of unconventional gas, especially from previously locked shale formations, the surge in means to move natural gas around the world via LNG and long-distance pipelines, and the decoupling in some markets of gas prices from those for oil and liquids all suggest the global natural gas industry may have entered a new era.

This vision gained some credibility at yearend 2010 when the international natural gas organization Cedigaz, Paris, reviewed major trends for the year. It noted that world natural gas production had increased by 4% over 2009 with only European production falling (Fig. 1). The same report, however, showed global gas trade in 2010 vs. 2009 contracted by 6.4%. The bright spot in that trade, however, was LNG, which increased its share of gas trade.

Oil & Gas Journal data show global gas reserves at Jan. 1, 2011, stood at 6,647 tcf, compared with 6,609 tcf at the beginning of 2010, an increase of nearly 38 tcf (OGJ, Dec. 6, 2010, pp. 48-49). Combined, the production and reserves figures should soften perennial concerns about the adequacy of global natural gas supply and stimulate overall gas trade in the near term.

Cedigaz emphasized that, although liquefaction capacity in 2010 rose, it is likely to see a much greater increase in 2011. The report's numbers paint a robust picture of the growth in liquefaction capacity from the end of 2010 through 2015, saying more the 48 million tonnes/year (tpy) of capacity will come on stream during the period.

Atlantic Basin LNG trade will rise at 9.5%/year over the period, reaching nearly 190 billion cu m for the trading region. In the Pacific Basin, trade will grow more slowly, at 4%/year…but grow nonetheless (Fig. 2). Regasification capacity 2009-15 will also see impressive growth, as 72 million tpy of import capacity were under construction at yearend 2010 and due to come on line by 2015, as much as 24 million tpy will be in Europe and 16 million tpy in the US (Fig. 3).

Cedigaz's analysis points to LNG markets moving from production overhang by yearend 2012 to probable supply "tensions" by yearend 2013.

Middle East

In December of last year, the Arabian Gulf state of Qatar celebrated reaching LNG production capacity of 77 million tpy, solidifying it as the world's largest single country supplier of LNG.

The celebration might have seemed a bit premature, since the massive trains clustered at Ras Laffan north of Doha only reached the 77-million tpy threshold with the start-up last month of Qatargas 4's 7.8-million-tpy Train 7. Nevertheless, the country has reached its position in a scant 14 years from the first production of LNG. In that time, its growth has overtaken other major producers of long standing, mainly Indonesia and Malaysia.

So confident that its position is unassailable and so concerned are the Qataris that reckless production might damage North field's reservoir that holds the world's largest non-associated natural gas reserves, that also in December of last year, the country's energy minister said flatly there would be no more large LNG projects. There will be only needed debottlenecking and revamping of the megatrains the country has built in recent years with cooperation of, among others, US international oil companies ExxonMobil and ConocoPhillips.

Qatar's decision also responds to forecasts of much higher gas demand among gulf states. In December, Qatargas delivered the first LNG cargo to Dubai via the permanently moored floating storage and regasification vessel Golar Freeze at the port of Jebel Ali (OGJ Online, Dec. 6, 2010).

The 210,000-cu m (Q-flex) Al Bahiya LNG carrier, dedicated under long-term contract by Nakilat to Quatargas Train 4, delivered the cargo intended for the local market under contract between Shell and the Dubai Supply Authority. The LNG was produced by Qatargas 2.

A report earlier this year from FACTS Global Energy said Dubai plans to meet gas demand of about 1.5 bcfd with pipeline imports from Qater, Abu Dhabi, and Sharjah, as well as the 400-MMscfd floating regasification and storage vessel moored at Jebel Ali (OGJ Online, Jan. 25, 2011). The gulf's first LNG importing country, Kuwait, started up a GasPort system from Excelerate Energy, Houston, in 2009.

The FGE analysis sees Dubai becoming a gas hub, importing LNG and exporting gas through existing pipelines to northern emirates.

Asia central

The centrality of Asia in global LNG trade was highlighted last year by a report from Denver-based analyst Bentek. It projected demand for LNG in Asia-Pacific by 2015 will reach 25.4 bcfd, up from 7.8 bcfd in 2010.

That demand growth will be pushed mainly by emerging demand centers China and India and by traditional demand centers in Japan, South Korea, and Taiwan as their economies recover from recession. In addition emerging markets in Bangladesh, Pakistan, Thailand, Singapore, and the Philippines will drive LNG demand growth.

An example of the growth of LNG imports into China is the month of August 2010. The country's General Administration of Customs reported LNG imports that month more than doubled those for August 2009: more than 995,000 tonnes exceeded volumes in 2009 by more than 115%. Those same August 2010 imports surpassed July 2010's figures by almost 40%. The increases were attributed to unseasonably hot weather and the ramp up of recovery from the global recession that hit almost 2 years earlier.

China's construction of LNG terminals continued apace in 2010 with Dapeng LNG in Guangdong province starting up an expansion, taking terminal inlet capacity to 6.7 million tpy.

In 2011, two more terminals will begin operating:

• Dalian in Liaoning province will start up 3.5 million tpy in its first phase.

• Rudong in Jiangsu province will start up its first-phase 3.5 million tpy.

At yearend 2011, China will operate 19.3 million tpy of inlet capacity, up from 3.7 million tpy in 2006.

Under construction are three terminals that will begin accepting shipments in 2012-13. Ningbo in Zhejiang province will start up its Phase 1 of 3 million tpy in 2012 for majority owner CNOOC; Quingao in Shandong province will start up its first phase (3 million tpy) in 2013 for owner Sinopec; and another CNOOC terminal is set to open in 2013 at Jinwan, Zhuhai, Guangdong.

Terminals in Tangshan (PetroChina, 2013), Hainan Island (CNOOC; 2014), Shenzhen, Guangdong (PetroChina, 2014+), and another in Shenzhen (CNOOC, unknown start-up) will be able to handle 11.5 million tpy. Four terminals have been approved for expansion and three others await approval by the National Development and Reform Commission.

In India, Asia's other major emerging LNG market, Royal Dutch Shell opened its Hazira LNG terminal on India's west coast to Gujarat State Petroleum Corp. The 132,000-cu m Iberica Knutsen reached Hazira with a cargo from Trinidad & Tobago, according to Reuters. Shell owns 74% of Hazira LNG Pvt and Total SA owns the rest. The terminal can handle 3.6 million tpy of LNG and can be expanded to 5 million tpy.

Petronet LNG Ltd. will install two more storage tanks at its LNG receiving and regasification terminal at Dahej in Gujarat. Added to the existing four tanks, this will raise total capacity to 15 million tpy from 10 million tpy. The company also reported it is in the process of setting up a second LNG jetty at Dahej to accommodate larger LNG carriers.

Petronet LNG, a joint venture of GAIL India, Oil and Natural Gas Corp., Indian Oil Corp., and Bharat Petroleum Corp., is also constructing a 2.5-million tpy terminal at Kochi with targeted commissioning of mid-2012.

For that terminal, Petronet has a long-term gas supply contract with ExxonMobil for LNG from Gorgon field. Plans to expand the terminal will increase capacity to 5 million tpy from 2.5 million tpy. The second phase will probably be added by third or fourth quarter 2012.

Although not a large market by Chinese or Indian standards, Singapore's installation of its first LNG terminal has wider implications for the region.

It is currently building a terminal to handle 3.5 million tpy and to open in 2013. In November last year, Singapore LNG announced plans to add a third storage tank at the Jurong Island site to be ready by early 2014. The new 180,000-cu m tank would take terminal capacity to 6 million tpy.

The third tank signals an expansion in the mission of the terminal itself. The initial terminal design envisioned small LNG cargoes of about 100,000 cu m. Cargoes of this size are adequate only for satisfying the terminal's commitment to BG for the initial 3 million tpy of capacity. Adding the tank allows it to expand its service to a variety of customers in the highly industrialized area, SLNG Chief Operating Officer Neil McGregor told OGJ.

McGregor said the terminal may eventually function as a part of an active gas hub for the wider region, taking cargoes of various sizes, moving vaporized LNG to a variety of industrial and petrochemical customers, and even perhaps sending smaller LNG carriers back out to local markets that have installed small-scale LNG storage and vaporization, as in Japan.

In late January of this year, Mitsubishi Corp. announced that partners in Indonesia's $2.8 billion Donggi-Senoro LNG project had reached a final investment decision (OGJ Online, Jan. 25, 2011).

Mitsubishi said the project is being spearheaded by PT Donggi-Senoro LNG, a joint venture of Mitsubishi and subsidiaries of Indonesia's state-owned PT Pertamina, and PT Medco International.

By second-half 2014, PT DSLNG aims to produce and deliver 2 million tpy of LNG, along with associated condensate of 47,000 boe/d. PT DSLNG has signed a heads of agreement for an LNG sales and purchase agreement with Chubu Electric Power Co. and Kyushu Electric Power Co, while negotiations are being finalized with Korea Gas Corp.

Mitsubishi said it will transfer its shares of PT DSLNG to a special purpose company (SPC), which will take over some of PT Medco's shares as well, bringing its total stake in PT DSLNG to 59.9%.

Mitsubishi said Kogas will also be a partner in the SPC, making the project the first joint LNG project among Japan, Korea, and Indonesia, and "opening up a new era of cooperation in the energy sector for these three nations," according to the announcement.

The partners in the SPC include Mitsubish 45%, PT Petamina 29%, Kogas 25%, and PT Medco Energi with 11%.

Mitsubishi said JGC Corp. will build the plant on Sulawesi Island under an engineering, procurement, and construction contract.

Australian supply

Last year saw advances on the supply side of the Asia-Pacific region, as well as on its market side.

In November, BG Group announced it had made an FID to proceed with its planned $15 billion coal seam gas-to-LNG plant on Curtis Island near Gladstone in Queensland. The two-train, 8.5-million-tpy plant will be built over the next 4 years along with field facilities in the Surat-Bowen basins and a 540-km (about 335 miles) pipeline from the fields to the plant.

BG Group expects first exports of LNG to begin in 2014 underpinned by agreements in Chile, China, Japan, and Singapore for the purchase of up to 9.5 million tpy.

In January 2011, another Queensland-based coal seam LNG project moved ahead: Partners in Gladstone LNG liquefaction project reached FID on the $16-billion (Aus), 7.8-million-tpy project. Australia's Santos, a 30% partner, said the company expects to begin exporting LNG in 2015.

Other partners are France's Total (27.5%), Malaysia's Petronas (27.5%), and South Korea's Korea Gas (15%). That ownership firmed up in 2010 after Santos agreed to sell Korea Gas and Total a 7.5% stake each. At the same time, Petronas also agreed to sell 7.5% of its GLNG equity to Kogas.

Kogas also agreed to buy 3.5 million tpy of LNG from the project. Its 20-year agreement provides for 1.7 million tpy of the contracted volumes to be delivered from GLNG Train 1 and 1.8 million tpy from Train 2.

Petronas also has a 20-year agreement to buy 3.5 million tpy of LNG from GLNG, of which 1.8 million tpy would come from Train 1 and 1.7 million tpy from Train 2.

Two other LNG export projects from Queensland's coal seam gas are likely.

In August 2010, Shell and PetroChina completed their $3.4 billion (Aus.) joint acquisition of Australia-based coal seam gas company Arrow Energy Ltd. Shell and PetroChina have taken over Arrow's coal seam gas assets in Queensland to backstop a planned four-train, 16-million-tpy plant to be built on Curtis Island.

At the time of the transaction Arrow held equity interests in more than 25,000 sq miles of CSG exploration tenements and five producing projects that accounted for about 20% of the state's gas consumption. Arrow was also developing a pipeline to move gas from the Surat basin to Gladstone.

In January of this year, the Shell-PetroChina joint venture invited tenders for the front-end engineering and design phase of its project; those tenders were due by the end of last month.

Stage 1 includes construction of two trains of 4 million tpy. An FID is set for 2012, leading to the project being on stream in 2017.

In November of last year, the Queensland government approved construction of a fourth LNG project based on CSG reserves. Australia Pacific LNG proposes yet another LNG plant on Curtis Island.

The $35 billion (Aus.) APLNG project, a 50:50 joint venture between Australia's Origin Energy and ConocoPhillips, now requires only environmental approvals from the Australian federal government in Canberra. The environmental clearances are the last major regulatory hurdles to be overcome by the project, although by January this year it had not announced the securing of any LNG customers.

APLNG project could eventually consist of up to four, 4.5-million-tpy trains. In addition to the plant, work involves further development of APLNG's coal seam gas resources in Queensland's Surat and Bowen basins, and Queensland environmental approval to build a 279-mile pipeline from the gas fields to Gladstone.

Under the APLNG joint venture, Origin would be responsible for building and managing the coal seam gas resources and related facilities, and ConocoPhillips would oversee construction of the LNG plant and export on behalf of APLNG.

This artist's conception shows an LNG carrier moored onto the floating liquefaction design for Shell's Prelude project off northwestern Australia (image from Shell; Fig. 4).

The other important news of the year out of Australia is the likely installation of the world's first floating LNG plant for Shell's Prelude project 475 km north-northeast of Broome on the Kimberley coast of northwest Australia (Fig. 4).

In March 2010, Royal Dutch Shell signed two contracts with a joint venture of France's Technip and South Korea's Samsung Heavy Industries for design and potential construction of the proposed Prelude floating liquefaction vessel. The first contract covers front-end engineering and design for the project; the second sets the terms under which the FLNG would be built, pending FID.

Shell had already signed a master agreement in mid-2009 with the Technip-Samsung consortium for design, construction, and installation of multiple floating LNG facilities over 15 years. In addition, Shell said in late 2009 the world's first FLNG production would be designed to produce 3.6 million tpy of LNG as well as 400,000 tpy of LPG and 1.3 million tpy of condensate.

It would include six LNG storage tanks with total capacity of 220,000 cu m, four LPG storage tanks with total capacity of 90,000 cu m, and six condensate storage tanks to hold as much as 126,000 cu m.

In October 2010, Shell reported it was on track to approve Prelude early in this year, despite several environmental delays during 2010. Those delays were resolved in November when Shell received environmental approval from the Australian government for Prelude.

Environment Minister Tony Burke imposed strict conditions on the development to protect the marine environment. Shell will have to develop an oil-spill contingency plan to the government's satisfaction that outlines how the company will minimize the risk of oil spills while also reducing the environmental impact of any spill.

In the event of a spill, Shell will be responsible for the entire bill for environmental rehabilitation and will have to develop a greenhouse-gas strategy that is "transparent and publicly available." Burke said his department would have the power to conduct a project audit at any time to ensure Shell is complying with the approval conditions.

With all going according to plan, Shell expects to begin commissioning in 2015 and produce its first LNG in 2016 (OGJ Online, Nov. 12, 2010).

US: an LNG exporter?

Whereas only a few years ago the US saw more than 50 proposals to import LNG, as analysts widely—and, it now appears, wildly—predicted a natural gas shortage in the country's immediate future, the likelihood now of the US exporting LNG from domestically produced natural gas seems very bright.

Last June, Cheniere Energy announced the first concrete plans to export US gas as LNG from the Lower 48 as it made plans to build liquefaction at its existing—and recently completed—import terminal on the Sabine Pass, Cameron Parrish, La. Cheniere announced it would export as much as 1 bcfd by 2015, possibly expanding later to 2 bcfd.

Major shale-gas producer Chesapeake Energy indicated its willingness to send as much as 500 MMcfd of its gas to the proposed liquefaction plant for export to higher-paying markets.

Cheniere's proposal to export LNG from its Sabine Pass terminal would cost $1.6 billion, if it finds market interest for four liquefaction trains with combined capacity of 14 million tpy.

An artist's rendering shows how liquefaction Phases 1 and 2 might be installed adjacent storage at Cheniere's existing Sabine Pass regasification terminal in Cameron Parrish, La. (image from Cheniere Energy; Fig. 5).

Cheniere has said in an application to the US Federal Energy Regulatory Commission that, through subsidiary Sabine Pass Liquefaction, it wants to start construction of the project in January 2012. Cheniere would build two 3.5-million-tpy liquefaction trains in Stage 1 and two more 3.5-million-tpy trains in Stage 2, providing sufficient market demand (Fig. 5).

Each train would employ ConocoPhillips's Optimized Cascade liquefaction technology and include gas treatment to remove condensates, water, solids, CO2, sulfur, and mercury. Each would have six LM2500-G4 turbine-driven refrigerant compressors.

The US Department of Energy in September approved Cheniere Energy's plans, moving the terminal closer to becoming the first facility ever in the Lower 48 and the first of a cluster of Gulf of Mexico import terminals to export natural gas produced in the US. On its web site, the company calls its plans the "world's first bidirectional LNG facility."

The DOE's approval allows Cheniere's subsidiary to export LNG to any nation that currently can import LNG and with which the US currently has entered or may in the future enter into a Free Trade Agreement, including Canada, Mexico, Chile, and Singapore.

Cheniere planned to file a separate application for authorization to export LNG to countries with which an FTA applicable to natural gas and LNG isn't in effect. This second application would be subject to more rigorous public interest review and analysis by DOE, the company said in the application.

In November came news that, under an agreement Cheniere Energy signed with ENN Energy Trading, natural gas production from the Lower 48 could be exported to China.

Cheniere said in a statement at the time that the memorandum of understanding could allow China's ENN to contract for 1.5 million tpy of bidirectional processing capacity at the Sabine Pass LNG terminal. Talks were to lead to a contract for 20 years with mutually agreed extension, subject to certain conditions. Those include Sabine's receipt of regulatory approvals and reaching FID to build liquefaction, and ENN reaching FID to build an LNG receiving terminal.

And only 2 months ago, Cheniere announced that Sabine Pass Liquefaction had signed yet another MOU, this time with EDF Trading, London (OGJ Online, Jan. 21, 2011).

Under that agreement, EDF Trading intends to contract for 0.7-1.5 million tpy of processing capacity at the Sabine Pass terminal. Under the MOU, EDF Trading, a wholly owned subsidiary of EDF SA, and Sabine Pass agreed to negotiate definitive agreements for EDF Trading to contract bidirectional capacity.

The agreement is subject to, among other conditions, receipt by each party of internal approvals, Sabine's receipt of regulatory approvals, and an FID by Sabine Pass to build liquefaction adjacent to the import terminal.

EDF stated it intends to enter into contracts for at least 500 MMcfd/train of liquefaction capacity. The announcement said LNG export could begin as early as 2015, assuming Sabine Pass obtains regulatory approvals and reaches FID.

The announcement came about the same time as the news that Cheniere had signed a non-binding MOU with Morgan Stanley Capital Group that would permit Morgan to buy import capacity and about 20% of a proposed 7 million tpy of liquefaction capacity at the South Louisiana terminal. Under the MOU, Morgan Stanley would be able to export or import 1.7 million tpy of LNG from the terminal (OGJ, Jan. 17, 2011, Newsletter).

And at the end of January, Cheniere Energy announced that subsidiary Sabine Pass Liquefaction had entered into yet another nonbinding MOU with Sumitomo Corp. under which Sumitomo intends to contract up to about 1.5 million tpy of processing capacity at the Sabine Pass LNG terminal (OGJ Online. Jan. 28, 2011).

Under the MOU, Sumitomo and Sabine have agreed to proceed with negotiations of definitive agreements for Sumitomo to contract bidirectional capacity, subject to certain conditions, including receipt by each party of requisite internal approvals, Sabine's receipt of regulatory approvals and reaching FID to construct liquefaction.

In September of last year, another newly built LNG terminal along the Texas Gulf Coast, at Freeport, Tex., loaded out a shipment of LNG as reexport aboard the 138,000 cu-m Excalibur, from Excelerate Energy's fleet This was the second such reexport for the terminal and reflected how LNG shippers can take advantage of US terminals to store and reexport gas to higher-priced markets in Asia and Europe.

In November, Freeport LNG and Macquarie Bank agreed to build an export plant on the terminal site. It would be able to export 1.4 bcfd equivalent in LNG by 2015 and will cost about $2 billion. Freeport LNG will operate the plant, with Macquarie contributing to development costs.

Macquarie and Freeport plan jointly to market half of the export plant's capacity, with the other half being offered to Freeport's existing import customers, Dow Chemical and ConocoPhillips.

Also in September, Sempra LNG applied to the FERC to export LNG from its very recently completed terminal in Cameron Parish downstream of the long-standing Panhandle LNG Lake Charles terminal. Cameron LNG asked for 2-year authority to reexport up to 250 bcf. In December, the DOE approved Sempra LNG's application to export; in late January, the FERC was still studying Sempra LNG's construction application.

The DOE order allows reexports to any country that can import LNG from ocean tankers and with which trade is not prohibited by US law or policy.

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