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The LNG business began in Africa. Almost 50 years ago, Algeria led the world into the age of liquefying natural gas, loading it aboard ships and delivering it to markets that could not be reached by pipeline. Algeria expanded its production in the 1970s and 1980s, followed by Nigeria in 1999, Egypt in 2005 and Equatorial Guinea in 2007.
Those four countries supplied almost 17 percent of the world’s LNG in 2012. And this year Angola plans to join the list of nations in North and West Africa feeding the fuel to consumers around the world.
The gas industry is now looking clear across the African continent for the next wave of LNG export operations.
“We’re all watching East Africa,” Joseph Geagea, president of Chevron Gas and Midstream, said at LNG 17, a global gathering April 16-19 in Houston where thousands of producers, customers, suppliers, governments and consultants mingled and talked deals.
In an industry that has proved highly unpredictable of late, notions of what new twists the LNG markets might take flew thick among attendees as they sat in on panel presentations and browsed elaborate exhibition booths sponsored by governments and companies.
Would Australia’s $200 billion expansion of LNG production pay off? How will U.S. Lower 48 export projects affect global supplies and prices? How many Canadian export projects will actually take root? Can the world’s biggest LNG producer, Qatar, keep its customers amid new competition? Can Japan find a way to bargain down the high prices it pays? Will Russia succeed in its ambitions to build LNG market share in Asia? Will European demand for LNG be strong or slack?
Source: Oxford Institute for Energy Studies
East Africa was high on the buzz list. Companies have discovered an estimated 120 trillion cubic feet of natural gas off the coasts of Mozambique and Tanzania and are looking east across the Indian Ocean toward the same Asian markets that are drawing most every other LNG supplier in the world.
The first and largest discoveries have occurred in Mozambique, on the southeastern side of the continent. With an estimated 100 tcf of reserves, the country is at the forefront of East Africa’s gas development. Texas-based Anadarko and Italy’s Eni have partnered to work toward building a gas production platform 35 miles offshore and piping the gas to multiple liquefaction trains onshore. Each train would have an average capacity of 650 million cubic feet per day. Eni has priced the whole project at up to $50 billion. The companies hope to begin exporting by the highly ambitious target date of 2018.
Norway’s Statoil has enjoyed similar exploration success off the coast of Tanzania, as has the U.K.’s BG Group. The two companies are looking at a joint LNG export development, drawing on gas from their adjacent blocks. A final investment decision is at least three years away, a Statoil executive said in March. ExxonMobil is involved through a partnership with Statoil.
East Africa’s advantages include large reservoirs containing high-quality gas in waters that are not too deep or far from land. Derek Hudson, president and asset general manager of BG East Africa, said the region has “good positioning for Asia-Pacific LNG markets” and is “a new exploration hotspot” that will “likely underpin the next wave of LNG developments.”
But challenges abound. The region’s major disadvantage is its shortage of the basic building blocks for industrial development. Roads, deep-water ports, housing and electricity grids are rudimentary or nonexistent. Technical staff and local labor will require training, with a substantial part of the workforce likely to come from abroad, Hudson said.
“We can get good East Africans in the international diaspora who would be happy, potentially, to go back,” Hudson said. He believes local vocational training programs and scholarships will also swell the ranks of qualified workers.
There is a cost to job training, however. An ExxonMobil subsidiary recently reported it spent $120 million on training and skill development for the LNG project it’s building in Papua New Guinea.
Raising the huge financial resources necessary to develop LNG export projects could pose another challenge for sponsors in East Africa. Prospective lenders will want to scrutinize the countries’ track records, which are blank when it comes to LNG exports. Mozambique and Tanzania are young democracies that rank among the world’s most impoverished countries. The World Bank’s report on Doing Business 2013 ranks Tanzania 134th and Mozambique 146th out of 185 countries for “ease of doing business.”
Despite the obstacles, some analysts see a possibility that project costs in East Africa will be lower than those in Australia, which is gearing up to become Asia’s largest LNG supplier.
LNG customers, too, are looking at East Africa. To gain greater access to financing and share the risk, Eni said in March it had agreed to sell a 20 percent stake in its giant Mozambique offshore field to China National Petroleum Corp. for $4.21 billion. It’s the latest in a string of overseas acquisitions by Asian companies aiming to secure oil and gas supplies.
SUPPLY: AUSTRALIA’S BIG MOVE
Vast natural gas resources and its proximity to big Asian importers are propelling Australia into the top position as an LNG exporter. But becoming the alpha of LNG suppliers has proved a pricey proposition. Australia’s gas-rich states are hosting big-ticket projects whose sponsors count on recouping billions in costs and, of course, profit, by securing high prices in Asia.
Currently the fourth largest exporter in the world -after Qatar, Malaysia and Indonesia-Australia is poised to be number one by about 2020, Hans Stinis, LNG strategy and portfolio manager at Shell International Exploration and Production, said in a conference paper at LNG 17.
Hiroshi Hashimoto, senior analyst at the Institute of Energy Economics, Japan, expects Australia to pull even with Qatar in LNG exporting capacity around 2018.
Seven large Australian LNG plants are under construction. The state of Western Australia has seen breakneck growth over the past decade, hosting mega-projects such as Chevron’s Gorgon and Wheatstone and Inpex’s Ichthys. Shell is building the world’s first floating LNG ship for its Prelude field off Western Australia’s coast. The 1,600-foot-long ship would fulfill all the functions of a land-based LNG plant, including production, liquefaction, storage and offloading to tankers for shipping.
The three other projects under construction-Queensland Curtis Island LNG, Gladstone LNG and Australia Pacific LNG-are in Queensland, in northeast Australia.
In total, Australia has about $200 billion worth of LNG projects under construction with combined maximum capacity of 8 bcf a day. With domestic demand relatively low, these projects are geared toward growing markets in East and Southeast Asia. Queensland Curtis is slated to be first of the projects to start shipping gas with a target date of 2014.
Still, analysts are wondering how East African and North American LNG might affect Australian exports.
“Many buyers have now started to consider whether they are too exposed to Australia, which, in our opinion, is likely to lead them to securing a lot of their next volumes from other geographic sources including East Africa, Canada and the USA,” Frank Harris, head of global LNG consulting at the research and consulting firm Wood Mackenzie, said in a conference report.
Source: Economist Intelligence Unit
Escalating project costs are one reason buyers are looking to diversify their supply sources. Gorgon, Queensland and Gladstone have reported construction cost increases of 43 percent, 25 percent and 15 percent, respectively, over estimates made at their final investment decisions. Reasons include increased labor costs, tough terrain, inclement weather, and the dramatic strengthening of the Australian dollar.
Currency movements matter for these projects because some of the costs are paid for in Australian dollars. To cover those costs, project sponsors buy Australian dollars, presumably with U.S. dollars or euros as they are the world’s major reserve currencies. When the Australian dollar strengthens, or becomes more expensive relative to the U.S. dollar or euro, the cost for those Australian dollars-and the project work they pay for-rises.
“The madness in Australia has to come to an end, and it will by 2016,” said Fereidoun Fesharaki, chairman of consulting firm FACTS Global Energy. “It will be good for all. There will be business, but there won’t be madness.”
Mad or not, companies continue to explore. Major companies including Chevron, BG Group, ConocoPhillips, PetroChina, Total, Hess and Statoil have been staking out positions in shale gas.
SUPPLY: NORTH AMERICA’S ENORMOUS RESERVES
Shale gas has spurred the swift metamorphosis of the United States from global buyer to possible seller of LNG. The Potential Gas Committee in April released a record high estimate for U.S. reserves at 2,384 tcf of technically recoverable natural gas (100 times the country’s total natural gas consumption in 2012). The Colorado-based industry nonprofit has issued biennial gas assessments since 1964.
Purchasers in Asia, the world’s largest LNG market, are eager for U.S. gas because the price is linked to Henry Hub, the most widely used reference point for gas prices in the country. In Asia, LNG prices are tied to oil prices on a Btu-equivalent basis. Oil at $100 a barrel pulls Asia’s LNG to about $15 per million Btu, more than three times the cost at Henry Hub.
Of course, the price gap narrows substantially with the added expenses of liquefaction and shipping across the Pacific. Still, U.S. LNG, at today’s gas prices, could arrive in Asia as $11 or $12 gas.
Whether that price spread will hold is a question that’s keeping market forecasters fully employed.
A presentation by consultancy Wood Mackenzie predicted rising domestic demand will boost U.S. gas prices, while LNG export project costs may go up as competition for materials and labor intensifies.
“The combined impact of rising feed gas prices and higher LNG development costs will likely restrict the volumes of U.S. LNG export capacity developed,” noted Frank Harris, head of global LNG consulting at Wood Mackenzie. “Nevertheless, we anticipate more U.S. LNG projects will be developed.”
Copyright Poten & Partners
The vibrancy of U.S. exports depends also on Department of Energy approvals for sending LNG to countries that are not free-trade partners with the United States. The first exports from the Lower 48 are expected by 2015 from a facility Cheniere Energy is building at Sabine Pass, La. So far, no other applicant has acquired a license to export to non-free trade countries. The approval is important because of all the major global buyers, only South Korea has a free-trade agreement with the U.S.
Twenty LNG export applications are awaiting decisions by the Department of Energy.
Opposition to exports comes from manufacturers such as Dow Chemical and others who worry that sending U.S. gas abroad will make gas at home more expensive or even lead to supply shortages. Environmental groups argue that exports will hurt Americans. Higher domestic gas prices would worsen air pollution by making gas less competitive against coal for electricity generation, they say. They also worry that an uptick in hydraulic fracturing to produce more gas will contaminate air and drinking water.
Canada wants in the game, too, and is weighing as many as 10 proposals for LNG exports from the British Columbia coast.
The Western Canadian projects all focus on large but remote shale gas reserves in the provinces of British Columbia and Alberta. The gas would need to cross two mountain ranges by pipeline to reach the coast. Unlike Lower 48 applicants that want to add liquefaction to existing gas import terminals, the Canadian projects would need to build their own LNG storage tanks, docks, jetties and pipeline connections.
LNG projects also would be competing with Western Canada’s growing oilsands industry for labor and materials, Harris said.
Given the challenges, “the outcome for these projects [in Canada] appears uncertain,” said Howard Rogers of the Oxford Institute for Energy Studies.
SUPPLY: QATAR WILL STAY COMPETITIVE
The Middle East is home to the world’s largest LNG supplier, Qatar, whose output capacity is 10 bcf a day. The country will not readily cede customers to competitors.
As new export projects emerge in Australia, and potentially North America and East Africa, Qatar’s marketers are “gearing up campaigns to secure long-term deals in the Asia-Pacific region, including Japan, Malaysia and Thailand,” said Hiroshi Hashimoto, senior analyst at the Institute of Energy Economics, Japan.
State-owned Qatargas delivers approximately one-sixth of the global LNG supply and has a market foothold in 75 percent of importing countries.
Company representatives at LNG 17 emphasized their continued focus on Asia.
The data illustrates the flow of pipeline natural gas and LNG between sources of production and regions of consumption. Trade flows are on a contractual basis and may not precisely correspond to physical gas flows in all cases.
“The mature Asian Japan/Korea/Taiwan markets will continue to dominate the demand for LNG in the region,” said Alaa Abujara, chief operating officer of the commercial and shipping division at Qatargas. The company plans to target China and India as new growth markets.
Australia is Qatar’s biggest up-and-coming rival, but competition on a smaller scale may arise closer to home. The Leviathan basin in the Eastern Mediterranean has added around 40 tcf of gas reserves since 2009, mostly in Israeli waters but also offshore Cyprus. Houston-based Noble Energy is at the forefront of exploring these resources.
Noble’s Gerald Peereboom told the LNG 17 crowd that the location of gas resources near the Suez Canal “will provide supply diversification for Asian buyers, as it is strategically located.”
Though Noble is looking at the LNG export option for its gas discoveries, Israeli politicians are struggling with the tricky politics of domestic use vs. export sales.
The big gas finds in the Eastern Mediterranean position the region to become a major LNG supplier, said Wood Mackenzie’s Harris.
The Middle East is also attracting LNG imports. Dubai and, to a lesser extent, Kuwait rely on gas-fired generation for electricity, and demand for power in both countries is on the uptick with economic growth. While the region is gas-rich, many countries reinject it to maintain pressure on oil fields, just as is done on Alaska’s North Slope.
With Qatar’s LNG supplies locked into long-term contracts with buyers and a government-imposed moratorium on further gas development, its Mideast neighbors are starting to look for additional supplies from outside the region.
SUPPLY: RUSSIA LOOKS EAST TO ASIA
As the world’s second biggest gas producer-second only to the United States-Russia sends the bulk of its export gas to Europe in pipelines, but dipping European demand has prompted the country to consider the more lucrative and growing Asian LNG market.
Russia touts its proximity to Asia-Pacific markets as an advantage over other suppliers.
“We are really close to buyers, only one or two days transport,” said Elena Burmistrova, deputy director general for Gazprom Export’s oil and gas products, LNG and new markets division, referring to the company’s Sakhalin-2 export terminal in the Russian Far East.
She said state-owned Gazprom may add a third train to Sakhalin-2, which in 2009 became the first (and so far only) LNG plant in Russia.
“We consider this project to be really successful. It’s like a pearl to us,” she said. Russian and Japanese companies are discussing additional LNG projects to add supply. There also are discussions of an undersea pipeline for gas deliveries to Japan, though Burmistrova said it was “not an option in the near future. That’s why we are potentially expanding the Sakhalin-2 project.”
Source: Poten & Partners
LNG prices vary by region. Asia is a predominantly oil-linked LNG market (tied to prices for Brent crude and Japan’s average price for imported oil, nicknamed the Japan Crude Cocktail). Prices in continental Europe reflect oil product-linked and hub-priced natural gas markets. Gas-on-gas market pricing dominates the United Kingdom (National Balancing Point), while much of Europe pays oil-linked prices. North American gas is tied to the Henry Hub pricing point. (Click to enlarge.)
She said Gazprom plans to stick with oil-linked prices, as “Henry Hub is not a natural pricing mechanism for Russia,” and to conventional gas, which she said “is more economic [than shale] right now.”
At 1,575 tcf, Russia had the world’s largest proved reserves of natural gas as of 2011, according to BP’s annual statistical report. With that much gas, there’s no need to explore unconventional resources. “We’re not going to develop shale gas in Russia within the next five to ten years,” Burmistrova said.
In addition to possibly expanding Sakhalin-2, Burmistrova said Gazprom is looking at building another LNG export terminal in the same region at the port city of Vladivostok. Siberian gas would be piped to Vladivostok, andpossibly into China. Gazprom targets 2018 as the start-up date for the plant. Discussions continue with potential customers.
Farther northwest, up in the Arctic, Russian producer Novatek is developing an LNG export project on the Yamal Peninsula. Novatek and its partner, France’s Total, look to split cargoes starting in 2016 between Europe and Asia, depending on the seasons and the open sea routes to customers.
DEMAND: PRICE PUSHBACK IN ASIA
Asia will continue to be the target market for sellers, but top importer Japan and its neighbors are pushing back on LNG prices and searching for cheaper energy substitutes. With LNG imports to blame for the country’s 2011 trade deficit-its first in three decades-Japanese panelists at LNG 17 expressed strong support for a trading hub in Asia that could bring some relief through spot and short-term LNG sales.
They are also looking to U.S. exports, linked to the Henry Hub price, to replace cargoes tied to the currently higher oil-indexed pricing used in Asia. The Development Bank of Japan estimates LNG import costs could fall by 7 to 15 percent by 2020 if buyers succeed in securing large quantities of LNG from the United States.
Japan’s buyers must find ways to strike better deals, said Hiroshi Hashimoto of the Institute of Energy Economics, Japan. “Buyers should develop proactive purchasing strategies to avoid excessive and unnecessary price rise under the current market conditions that appear to be more favorable to LNG sellers.”
Source: Data from Customs Statistics of Japan
He proposed several possible solutions for Japan’s buyers:
- Striking liquefaction tolling deals with U.S. LNG plant operators to guarantee the Henry Hub price by buying gas at the source. The buyers would pay for liquefaction and shipping, and take the risk if U.S. gas prices spike as they have several times in the past decade.
- Sponsoring shares of LNG export projects to better influence gas sales prices.
- Forming a Japanese buyer consortium to improve bargaining power.
- Importing pipeline gas from Russia.
Sellers also are watching Japan’s review of its nuclear policies. Prime Minister Shinzo Abe does not support a total and permanent ban on nuclear power, and wants the country to draw 15 to 20 percent of its electricity from atomic energy. The country is also pushing energy-efficiency programs and more aggressive development of geothermal and other renewables to reduce the need for LNG.
Conference attendees were also keenly interested in the growing LNG markets of China and India.
Heavy air pollution in China caused by the widespread burning of coal is driving a move toward cleaner-burning natural gas. The International Energy Agency predicts China could import up to an average of 4.8 bcf per day of LNG by 2015, essentially tripling its LNG imports of 1.6 bcf a day in 2011.
Analysts project even greater growth over the long term. “We expect the Chinese gas market in 2030 to be around the same size as the European gas market is today at some 54 billion cubic feet a day,” said Hans Stinis, LNG strategy and portfolio manager at Shell International Exploration and Production.
China plans to develop its substantial shale gas reserves in an effort to meet a portion of its ever-growing energy demands, but sparse geological data, challenging terrain, lack of roads and a pipeline network, and the need to acquire technological know-how are all hurdles to ramping up domestic supply.
“The geology, technology and national politics in China are all different from the United States, so we don’t think in five, 10 or 20 years there will be big shale gas development in China,” said Chen Bo, vice president of the foreign affairs department at Sinopec, a Chinese government-owned petroleum and chemical company. “So it’s a dream.”
Meanwhile, the CEO of India’s largest natural gas importer expects LNG imports there to jump to 5 bcf a day by 2016-17 up from 1.6 bcf a day in 2011. A growing population and economy are upping the need for more energy and LNG imports are crucial, given that domestic supply is not expected to keep pace.
A.K. Balyan, CEO of Petronet LNG, said India, the world’s sixth-largest LNG importer, “is likely to be third-largest importer of LNG by 2020.” But he acknowledged India “faces stiff competition” from the Big Three LNG importing countries (Japan, South Korea, Taiwan), which import around 50 percent of total LNG traded worldwide. He also noted that fellow newcomer China has been “very aggressive” in securing LNG. Competition on the buyer side may present India with some challenges in locking down prices it finds palatable.
DEMAND: EUROPEAN IMPORTS DOWN
The economic downturn and a marked shift from natural gas to cheaper coal, along with national commitments to renewable energy and greater energy efficiency in Europe, has pushed overall natural gas imports below 2001 levels. Demand for both piped natural gas and LNG fell by 10 percent from 2010 to an average of 43.3 bcf a day in 2011. In 2001 Europe imported an average of 43.7 bcf a day of natural gas.
But a slow increase in demand, combined with declining regional gas production, will create a supply gap in both piped and liquefied natural gas totaling almost 9.7 bcf per day by 2030, said Denis Bonhomme, executive vice president for strategy at GDF Suez, a France-based global supplier of natural gas and electricity.
Where that gas will come from isn’t yet clear. Bonhomme said it will be a “tough competition between natural gas imported by pipelines and LNG.” Europe buys more of its imported natural gas from Russia’s Gazprom than from any other supplier, but is dissatisfied with the high price. LNG sellers are looking to make inroads into the market, which Gazprom will likely move to protect.
Jeannette Lee
Researcher/Writer for the OFC (Office of Federal Coordinator)
Above article has been initially published atArcticgas.gov and is reproduced here with author’s kind permission.
