LNG UPDATE: Shale, East Africa plays could boost global LNG supplies

April 2, 2012
If global LNG players looked to 2011 for clarity about and even solutions to some of their most vexing problems—a global imbalance in supply and demand chief among them—the year must have disappointed.

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

If global LNG players looked to 2011 for clarity about and even solutions to some of their most vexing problems—a global imbalance in supply and demand chief among them—the year must have disappointed. Indeed, the year served mostly to cloud some near-term trade and project prospects. And, developments so far in 2012 appear no more promising.

The Gate LNG terminal at Rotterdam, the Netherlands, officially opened in September 2011 when the 266,000-cu-m (Q-Max) Bu Samra LNG carrier arrived with its cargo from Qatar Liquefied Gas Co. (Qatargas). With throughput capacity of 12 billion cu m/year of natural gas, Gate terminal is the first LNG import terminal in the Netherlands. Photograph from Gate LNG.

A year ago, just as industry players faced prospects of global oversupply of LNG, wrought by a rush of new liquefaction capacity and the lingering effects of a general global recession, an 8.9 magnitude earthquake hit off Tohoku eastern Japan. The subsequent 23-ft tsunami swamped large portions of the country, killing an estimated 16,000 people and knocking out the country's nuclear-generation capacity. How the country has responded in the past year and specifically what effect the disaster has had on global LNG trade are discussed on p. 128.

Prospects for production and export of huge volumes of cheap natural gas from North America, mainly the US, created yet another cloud over the LNG industry in 2011 and into 2012. With proven reserves of natural gas in shale plays growing with each new study, several projects to liquefy and export it threaten to flood the world in 2015-17, in some views.

As 2012 began, OGJ data showed start-up during 2011 of QatarGas's 7.8-million tonnes/year (tpy) Train 7. Current information for 2012 indicates 14 million tpy of liquefaction will come on line by yearend, spread among Algeria, Angola, and Australia.

But in 2014, more than 41 million tpy are set to start up. Nearly 30 million tpy of that will be from Australia, while capacity additions in Indonesia and Papua-New Guinea round out the remaining likely new liquefaction.

To handle a large slug of supply capacity that came on line in 2009-10, nearly 39 million tpy of regasification capacity came on line last year. In 2012, less than half that—nearly 17 million tpy—will be added. But in 2013, a whopping 58 million tpy of regas capacity is set to become operational.

Shale potential

No industry gathering on global natural gas trade in the past 15-18 months has failed to devote considerable time and attention to the development of natural gas from shales in North America. The effect of this potential new supply source has rippled out to the rest of the world to become a major component not only in the plans for production projects but also for prospects of moving natural gas as LNG around the world.

Whether production from shales elsewhere in the world ever comprises a large portion of global natural gas supply, the perceived, near-term potential for gas exports as LNG from the US and Canada is playing a major role in plans for all the world's markets.

In the grand scheme of things, however, shale gas in North America has far more serious implications for the gas liquids side of the business than for LNG. That's because in both Canada and the US, exploration in shale plays has been driven by persistently high crude oil prices, prompting midstream operators to concentrate on wetter areas in the shale basins.

New infrastructure is planned and being rapidly built to move and fractionate the liquids and send them either to new US petrochemical plants or into markets outside the US.

The inevitable production of dry gas, either directly or as residue gas from the tailgates of gas plants that have separated out the liquids, combined in first-quarter 2012 with overall unseasonably warm temperatures to force Henry Hub vapor prices into the mid and low $2 range. Natural gas storage levels set records for the time of the year.

From this phenomenon—low vapor prices—there follows the push by some in the US to export "excess" natural gas in the form of LNG into regions where the vapor price is well above North America's even after the added costs for liquefaction and transportation.

Japan, for one, wants US-produced LNG and last month was publicly lobbying the US government to allow exports. Such exports can begin no earlier than 2016 and would likely take advantage of the newly expanded Panama Canal, set to open a new set of locks in late 2014.

In fact, at press time, only one LNG export project—Cheniere Energy's Sabine Pass terminal in southwestern Louisiana—had begun the extensive, expensive, and time-consuming stage of gaining approvals from the US Federal Energy Regulatory Commission. Cheniere also wants to build liquefaction at Corpus Christi, Tex.

Several other applicants shipping LNG have gotten export licenses from the Department of Energy, a much shorter and less expensive and arduous process.

But what has the rest of the LNG world worried or elated—depending on perspective: LNG producer or LNG importer—is the prospect of the massive natural gas reserves that could find their way onto the global market.

East Africa LNG

In addition to the prospects for North American shale gas development to push natural gas as LNG into global markets, there has appeared on the supply horizon yet another potentially large source of supply, this from East African fields off Mozambique.

A more detailed discussion of upstream developments in this area appears on p. 70 of this issue. For here, the relevant information is the potential LNG supply.

In November 2010, Anadarko Petroleum Corp., reporting a third large natural gas discovery in the Rovuma basin off Mozambique, said the three discoveries together were more than sufficient to support an LNG export project (OGJ Online, Nov. 29, 2010). At the time, Anadarko did not reveal estimated reserves.

In August 2011, results of an appraisal well near the Barquentine discovery off Mozambique added confidence to Anadarko's plans for a 10-million tpy LNG plant fed by gas from Offshore Area 1 discoveries. Anadarko has estimated the cost of the plant at $8-10 billion.

Estimated 6 tcf of reserves were sufficient for an Anadarko subsidiary and co-owners in Area 1 to award contracts to KBR and Technip to perform prefront-end engineering and design (pre-FEED) studies for the LNG plant.

By late 2011, Anadarko announced 15-30 tcf or more of estimated recoverable resources in Area 1 and said it was advancing a two-train LNG plant, expandable up to six trains. Final investment decision (FID) was planned for 2013 with first production in 2018.

Speaking to an industry group in December 2011, Anadarko's Brad Defenbaugh said that Mozambique LNG would be cost competitive with other operating and planned LNG production projects. He said the project could come in at about $9/Mcf at cumulative peak capacity, comparable with Northwest Shelf's Train 5 and much below, for example, Wheatstone (about $12.75/Mcf) and Yamal LNG (about $13.90/Mcf).

Defenbaugh also said that by 2020 with six trains producing 30 million tpy, Mozambique LNG could rank fifth among LNG-producing countries, led by Australia by that time.

Operating in Area 4 off northern Mozambique, an Eni SPA group announced in October 2011 a giant gas discovery that the company called the largest operated find in its history (OGJ Online, Oct. 20, 2011).

Eni said the Mamba South-1 discovery well "can lead to at least 15 tcf of gas in place in the Mamba South area."

Tokyo Gas commissioned the 175,000-cu-m Energy Horizon in August 2011 to carry LNG from Woodside's Western Australia Pluto LNG project, scheduled to send out its first cargo in first-half of this year. Tokyo Gas holds a 5% equity stake in Pluto and a 15-year contract to buy as much as 1.75 million tpy of LNG from it. Energy Horizon was built by Kawasaki Heavy Industries at its Sakaide, Kagawa prefecture, shipyard. Photograph from Kawasaki Heavy Industries.

The volume of natural gas discovered will lead "to a large scale gas development with a combination of both export to regional and international markets through LNG and supply to the domestic market."

In statements last month, Anadarko Vice-Pres. for Operations Don MacLiver said Anadarko and Eni were already in discussions aimed at unitization.

Announcements earlier this year have further solidified the LNG potential of the region.

In late February, Statoil and ExxonMobil reported gas shows in deep water 80 km off mainland Tanzania and 160 km northwest of Areas 1 and 4, which were noted previously as being operated by Anadarko and Eni, respectively, in the Ruvuma basin.

The Zafarani well is also 100 km north of the Ophir Energy PLC-BG Group's Chaza gas discovery on Block 1 about 18 km off Mnazi Bay, Tanzania, also in the Ruvuma basin. Zafarani is also 115-120 km south of Ophir-BG's Chewa and Pweza gas discoveries on Tanzania offshore Block 4 in the Mafia Deep subbasin and 75 km east-northeast of Songo Songo gas field (OGJ Online, Apr. 4, 2011).

Ophir-BG has pegged Pweza and Chewa, drilled in 2010, with contingent resources of 1.7 tcf and 611 bcf, respectively, and Chaza, drilled in 2011, with 92 bcf (OGJ, Feb. 27, 2012, p. 22).


Two projects on the eastern side of Australia and based on coal seam gas (CSG) produced from Queensland's Surat and Bowen basins are well under way, as reported last year:

• Queensland Curtis LNG, a planned two-train, 8.5-million-tpy project owned by BG Group, CNOOC, and Tokyo Gas. Start-up targets 2014.

Early in 2011, with all capacity contracted to China, Japan, Chile, and Singapore, BG unit QGC was marketing gas for a proposed third train. The Curtis Island plot can accommodate up to 12 million tpy.

• Gladstone Fisherman's Landing LNG, a two-train, 7.8-million-tpy project owned by Santos (30%); Malaysia's national oil company Petronas (27.5%); Total (27.5%); and Korea Gas (15%). Construction is under way with first production planned for 2015, according to the company's web site.

Another CSG-based project making major progress in 2011 and early 2012 is Australia Pacific LNG.

In early 2011, the joint venture of Origin Energy Ltd., Sydney, and ConocoPhillips, received environmental approval from the Australian government for its planned $35 billion (Aus.) coal seam gas-based LNG project on the central east coast of Queensland (OGJ, Mar. 7, 2011, p. 101).

The approval depended on several environmental strategies and ongoing monitoring and reporting requirements being put in place.

In July, APLNG partners took FID on Phase 1 of the planned two-train project (OGJ Online, July 29, 2011). The $14-billion first phase will consist of a 4.5-million-tpy LNG train and supporting infrastructure, with plans for a second train.

The overall 9-million-tpy project will cost $20 billion. The plant will be built on Curtis Island near Gladstone and fed with gas from several CSG fields in the Surat and Bowen basins.

Train 1 is underpinned by a 4.3-million-tpy offtake agreement with China Petroleum & Chemical Corp. (Sinopec Corp.). Sinopec also became a 15% stakeholder in the project for about $1.6 billion; ConocoPhillips and Origin each retained a 42.5% interest.

First production from Train 1 is set for 2015. Depending on supply negotiations, Train 2 could be on line in early 2016.

Finally, in December, Sinopec agreed to pay another $1.1 billion to increase its stake to 25%. The purchase reduced ConocoPhillips and Origin's holdings to 37.5% each (OGJ Online, Jan. 12, 2012).

Also as part of the deal, Sinopec will increase its take of LNG from the project to 7.6 million tpy of LNG through 2035, which firms up the planned second LNG train of the project.

Sinopec's involvement in APLNG will underpin its planned Guangxi LNG regasification terminal and possibly direct LNG to its other proposed LNG regasification terminals in China.

Yet another LNG project that will tap CSG in Queensland is Arrow Energy Ltd.'s Queensland LNG. Arrow is jointly owned by Shell and PetroChina.

The project took a major step forward in late 2011 when it made an offer to buy CSG producer Bow Energy. A spokesperson said the company was looking at 4.0 or 4.2-million-tpy trains as a "base case"; the added reserves from the Bow purchase could permit larger trains.

Arrow LNG is to come on line around 2017 with expansion plans to double liquefaction capacity to 16 million tpy. An FID is not expected before late next year.

In August of last year Arrow awarded FEED contracts for the two-train, 8-million-tpy LNG plant to an international consortium of Chiyoda Corp., CB&I, and Saipem.

On the western side of the country, where all LNG projects are based on conventional offshore-gas developments, owners of the Ichthys LNG project off northwest Australia announced earlier this year they had reached FID on the $34-billion development (OGJ Online, Jan. 13, 2012).

Ichthys owners are France's Total (24%), and Japan's Inpex (72.805%), Osaka Gas (1.2%), Tokyo Gas (1.575%), and Toho Gas (0.42%).

Ichthys field, discovered in 2000-01, holds estimated reserves of 12.8 tcf of gas and 527 million bbl of condensate. The project is to come on line at yearend 2016.

The two-train, 8.4-million-tpy project is based on an estimated 40-year supply of gas and condensate reserves in the Browse basin. The gas will move through a nearly 500-mile subsea pipeline to the LNG plant to be built at Blaydin Point near Darwin, Northern Territory. Condensate will be sold via a floating production, storage, and offloading vessel at the field, off northern Western Australia.

The investment brings total capital committed to LNG in Australia to more than $183 billion. In addition, Ichthys is the largest single private-sector investment ever made in the Northern Territory.

In a major LNG development late in 2011, Chevron reached FID on its $28.4 million Wheatstone LNG project.

It will develop natural gas reserves in the Carnarvon basin and build two 4.45-million-tpy LNG trains at Ashburton North, 8 miles west of Onslow, Western Australia. The land-based facilities will also include a nearly 190 MMcfd gas processing plant.

Partners in the onshore portion of the project are Chevron (73.6%), Apache (13%), Kuwait Foreign Petroleum Exploration (7%), and Shell (6.4%). A joint venture of Chevron and Shell owns Wheatstone and Iago fields, which will provide 80% of the plant's gas feed. The remaining 20% would come from Apache and Kufpec's jointly developed Julimar and Brunello gas fields.

In August 2011, the state of Western Australia gave the project its environmental approvals. In September 2011, Wheatstone received final federal government approvals for a 25-million-tpy LNG plant (OGJ Online, Sept. 23, 2011), implying later installation of an additional three trains. First gas from Wheatstone is expected in 2016.

By far the most dramatic turn for LNG development not only for off Western Australia but for the world came in May of last year when Shell announced it was moving ahead with floating liquefaction to develop its Prelude project in the Browse basin (OGJ Online, May 20, 2011).

Shell has begun building what will be the world's largest vessel every built: 488 m long, weighing 600,000 tonnes. The vessel, estimated by some to cost $110 billion, will be capable of producing 3.6 million tpy of LNG, 1.3 million tpy of condensate, and 400,000 tpy of LPG.

Initial design of the vessel was by South Korea's Samsung Heavy Industries along with France's Technip; construction will be by Samsung at its Geoje shipyard starting this year.

The project will develop Prelude and nearby Concerto gas fields in permit WA-371-P with total reserves of 3 tcf of gas and about 120 million bbl of condensate.

FLNG hookup and installation will take 6 months in advance of commissioning in 2015 and readiness to come on stream in 2016. Shell says the cycloneproof vessel will remain moored on Prelude for 25 years and cater to other field developments in the surrounding area where Shell has interests.

Only last month, Japan's Inpex Corp. said it would buy a 17.5% stake in Prelude FLNG (OGJ Online, Mar. 19, 2012). Apparently, the company plans to put the experience it gains on Prelude to use on its Abadi FLNG project off Indonesia. Last year, Inpex sold Shell a 30% stake in Abadi (OGJ Online, July 22, 2011).

Activity—China; India

Natural gas demand among Asian countries is driving several terminal projects, even among such perennial LNG suppliers as Indonesia and Malaysia, which ranked No. 2 and No. 3, respectively, as LNG exporters in 2010.

Last year, Indonesia started up a 3.8-million-tpy floating storage and regasification unit (FSRU) in Jakarta Bay even as it was advancing plans elsewhere for additional liquefaction capacity. And Malaysia expects to open a 3.8-million-tpy jetty-based terminal (FSRU) this year.

But the Asian countries whose natural gas demand is driving by far most LNG terminal development are China and India.

PetroChina commissioned its 3.5-million-tpy LNG terminal at Rudong in Jiangsu province in 2011, beginning with its first cargo in May from QatarGas and completing the process in November.

The terminal is owned by Kunlun Energy of Hong Kong (55%), Pacific Oil and Gas (a member of RGE Group, Singapore; 35%), and the local government investment company Jiangsu Guozin (10%). PetroChina owns 50.74% of Kunlun Energy.

PetroChina's first LNG terminal in China, Rudong is expected to be supplied mainly with LNG from Australia's Gorgon project, scheduled to start producing in 2014.

Also late last year, PetroChina received the first commissioning cargo for its other terminal, at Dalian in Liaoning province. Capacity is set at 3 million tpy.

A planned second-phase expansion would bring capacity at the Dalian terminal to 6 million tpy. In the long term, the terminal could be expanded to 10 million tpy. Qatar, Australia, and Iran will be Dalian's main suppliers.

Owners of Dalian are Kunlun Energy (75%), the port of Dalian (20%), and the local government's investment arm Dalian Construction Investment (5%).

In mid-2011, China National Offshore Oil Corp. (CNOOC) received final approvals for its $1.02-billion LNG terminal planned for Hainan Island.

The 2-million-tpy Hainan LNG terminal will be built and operated by CNOOC Hainan Natural Gas, a joint venture between CNOOC (65%) and Hainan Development Holdings (35%). It will be located at Heiyangang in the Hainan Yangpu Economic Development Zone.

Construction of two 160,000-cu m storage tanks and berthing to accommodate LNG carriers up to 267,000 cu m is to be completed by 2014; full operational capacity will come on line in 2016.

Phase 2 of the project, to be completed 2017-20, will add 1 million tpy.

Next year, China will join the ranks of countries employing floating regasification, if CNOOC's first-phase plans for floating LNG off the northern city of Tianjin reach fruition.

In October 2011, CNOOC began building facilities for floating LNG regasification and storage in an enterprise consisting of CNOOC subsidiary CNOOC Gas & Power, Tianjin Port, and Tianjin Gas Group. Relative ownerships have not been disclosed.

The companies are investing about $905 million in a two-phase project consisting of 2.2 million tpy of floating capacity and, in the second phase, 6 million tpy of regas capacity in a traditional land-based terminal ready by 2015.

Platts reported that France's GDF Suez signed an agreement to supply CNOOC with a floating storage and regasification vessel, the 145,000-cu m GDF Suez Cape Ann, of which the company took ownership in 2009. It has sendout capacity of 741 MMcfd.

According to Platts, GDF Suez and CNOOC signed a 4-year LNG supply agreement in October 2010 covering the supply of 2.6 million tonnes from 2013. The planned operation of Phase 1 of the Tianjin terminal is set for 2013.

The second phase, due to start up in 2015, would add the 6-million-tpy onshore terminal and include four 160,000-cu m storage tanks. The site can accommodate up to 10 tanks of equal size.

Platts also reported that CNOOC's Tianjin FSRU would be moored southeast of Nanjiang port in Tianjin harbor, Bohai Bay.

Several Chinese operating companies are exploring or planning floating storage and regasification because available plots for land-based terminals along China's coastlines are scarce and competition among developers for sites is fierce.

India last year started up the much-delayed 2.5-million-tpy first phase of the Kochi LNG terminal at Puthuvype. A 2.5-million-tpy second phase is due to be operating by yearend 2013.

Commissioning should finally be getting under way this month on India's 5-million-tpy Dabhol LNG terminal in Ratnagiri, on the west coast in Maharashtra. The terminal was to have begun commissioning in April of last year, but that was delayed by channel dredging needed to accommodate 160,000-cu-m LNG carriers.

In March, the LNG FSRU Excelerate took on a cargo at Statoil ASA's Snohvit plant on Melkoye Island off Norway and embarked for India. It is to arrive this month, the first of three or four cargoes in the commissioning process.

GAIL and state-owned power utility National Thermal Power each has 29.65% in Ratnagiri Gas and Power, which owns the Dabhol terminal.

Dabhol would be India's third largest regasification terminal, behind Petronet's 11.65-million-tpy Dahej, which started up in 2004 and was expanded in 2009, and Shell's 3.6-million-tpy Hazira terminal, which started up in 2005, was expanded in 2008, and plans an additional 1.4 million tpy for 2013.

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