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LNG sellers, buyers talk differences LNG Producer-Consumer Conference 2014 in Tokyo hears views on cost, price from those buying natural gas and those producing LNG Bill White Researcher/writer for the Office of the Federal Coordinator
Asian LNG consumers said the market has taken its first steps away from costly oil-linked pricing and other contract terms they have chafed under in recent years, and they anticipate further, more extensive reforms in the coming years.
Liquefied natural gas producers acknowledged the marketplace is indeed evolving but that a fundamental truth underpins the industry: New LNG export projects are extraordinarily expensive and need the support of high enough prices to justify undertaking the sizable construction investments.
These two views emerged from the LNG Producer-Consumer Conference 2014 on Nov. 6 in Tokyo, sponsored by the Japan Ministry of Economy, Trade and Industry and the Asia Pacific Energy Research Centre.
The first two such conferences that the Japanese government called - two years ago and last year - were notable for the palpable animosity LNG buyers aimed at producers. The Asian LNG price is the world’s highest - much higher than natural gas prices in North America and Europe - and buyers argued the price was unfair, unjustified and unsupported by supply-and-demand fundamentals. They felt they were being bilked.
At this year’s conference, some thawing was evident. Buyers didn’t belabor the “Asian price premium” theme as in previous years. For their part, sellers were less dug in with warnings about the perils of change.
That friction exists between buyers and sellers is nothing unique to the LNG marketplace. Such tension is as old as commerce.
That Japan has stepped forward to lead the discussion about what happens next makes sense considering Japan is the world’s No. 1 LNG consumer, taking 37 percent of the LNG produced last year.
Japan’s economy has been double-whammied by LNG imports since 2010: Its demand soared just as the oil-linked price also was soaring.
Global oil prices 2011-2013 averaged four times the price of a decade earlier. Demand soared due to the shutdown, after the 2011 earthquake and Fukushima nuclear disaster, of all of the country’s nuclear-power reactors. Electric utilities imported more LNG, coal and oil as replacement fuels. Rising fuel imports caused Japan to start running painful trade deficits that have grown annually and continue to grow this year.
An example of how one Japanese buyer has adapted to create more maneuverability for itself since 2011 came from Akihisa Mizuno, president and director of Chubu Electric Power, one of Japan’s larger electric utilities.
Chubu has been signing more purchase contracts for short- and mid-term lengths rather than the 15- or 20-year contracts that sellers prefer, Mizuno told the over 1,000 people attending the Nov. 6 conference. Chubu also has signed more contracts that don’t lock in an LNG shipment to a single destination.
And some recent contracts have strayed from the decades-old tradition of linking the LNG price to oil prices by blending a U.S., British, Asian or other natural gas price index into the formula, he said. In addition, this year Chubu has taken steps to form purchasing alliances with other LNG buyers in Japan and India in an effort to increase market power.
A change in the marketplace, at least in a small way, seemed clear at the conference, but less clear was whether the balance of power has shifted from sellers to buyers.
Paralyzing unknowns If change is coming in steps to the Asia LNG industry, it’s because a handful of gigantic unknowns loom, and no one is exactly sure how to bet them.
These include:
•How quickly will Japan restart its nuclear-power reactors? Before the 2011 earthquake and Fukushima nuclear disaster, Japan’s 48 reactors supplied 32 percent of the nation’s electricity. Today it’s 0 percent. Two reactors likely will restart in early 2015, Takayuki Ueda, commissioner of Japan’s Agency for Natural Resources and Energy, said at the LNG conference. Applications to restart 18 other reactors are pending, he said. LNG imports have risen 24 percent since 2010 to offset the loss of nuclear power.
•How much will Japan’s utility reform reduce demand? In the face of rising electricity rates post-Fukushima, the Japanese government in June 2014 decided to open its residential electricity market to full competition starting in 2016, ending the reign of 10 regional monopolies. Other reforms also are getting rolled out.
•How fast will China’s demand for natural gas grow, and how much will be met by domestic production vs. pipeline imports vs. LNG imports? How quickly can China develop its substantial shale gas resources? This year’s conference included its first speaker from China, who was bearish on China’s LNG outlook. Dai Jiaquan, director of the Oil Market Department at CNPC Economic & Technology Research Institute, said pipeline gas imports beat LNG on price. Further, LNG is losing its price advantage over oil and is uncompetitive with coal as a power-plant fuel. China’s LNG import terminals were used at just 52 percent of capacity last year, a rate that will fall to 41 percent in 2015, he predicted. LNG’s best use is for gas storage and for extra power at peak times at power plants, he said.
•How quickly will renewable energy catch on throughout Asia?
•How much LNG will North America export, and how much will those exports change the market? The first exports from the U.S. Lower 48 are scheduled to sail from Cheniere Energy’s new plant at Sabine Pass, Louisiana, in late 2015. Cheniere’s LNG challenges the status quo in two ways. First, it is priced at U.S. market prices, plus a liquefaction fee and a shipping fee. This challenges the Asia LNG pricing norm that uses a formula based on oil prices. (The Cheniere price model would have beat oil-linked prices in Asia since 2009 if it had been used, but at today’s $80 oil it’s questionable.) Second, the LNG buyer may deliver the gas anywhere in the world. This challenges the Asia LNG delivery norm that requires a cargo to land and be used at a specific port, a “destination clause” that protects the LNG seller from seeing that gas back out on the market in competition. Two other U.S. plants began construction in 2014 and a decision on another is imminent. More in the Lower 48 and Canada are proposed. All would tap North America’s abundant shale gas resource. Small volumes from North America might not affect contract terms elsewhere very much. Large volumes could affect terms a lot.
These and other factors have slowed some decisions to build new LNG plants in recent years, even as growing market demand has pushed developers to propose multiple projects.
This hesitation is a problem, said Peter Coleman, chief executive of Woodside Energy, an Australian LNG producer. LNG projects take a long time to develop. Investments are needed now to prevent supply shortages in 2021 and beyond, he said.
Trillions in investment needed Despite about 80 million metric tons a year of LNG capacity (almost 4 trillion cubic feet of natural gas a year) under construction - which will boost worldwide capacity by roughly one-third - forecasts at the conference predict many, many more plants will be needed.
Jean-Pierre Mateille, vice president for trading at Total Gas & Power, said industry capacity must double to 500 million metric tons a year by 2030.
Rob Franklin, president of ExxonMobil Gas and Power Marketing, said an additional 200 million metric tons will be needed by 2025 beyond what’s under construction now.
The industry needs to expand at six times the pace of the 1990s and twice the pace of the 2000s, Franklin said. And there is no such thing as low-cost LNG development these days, he said. Franklin estimated the total cost for the new construction through 2025 at $2.5 trillion.
Coleman with Woodside agreed LNG investments aren’t for the meek. “Even the cheap ones are $5 billion. The expensive ones are $50 billion.”
The producers were unanimous that long-term sales contracts must continue as the foundation of LNG projects.
Franklin called them “critical enablers of new investment.”
Coleman said LNG project developers bear so many risks, including price volatility, infrastructure problems, skilled labor shortages, regulatory delays, cost overruns and gas supply adequacy, to name some. Projects need long-term contracts with strong pricing to go ahead.
No one builds an LNG project for the spot market, he said.
Roger Bounds, global head of Shell LNG, said long-term contracts are even a mainstay of the new U.S. LNG plants under development, which are a new model for how to market LNG. Rather than being owned by the same companies that produce the gas being liquefied, the U.S. LNG projects generally are independent businesses whose only function is to build the plant and provide liquefaction services. Others produce the gas, pipe it to the plant, find buyers and ship LNG to them.
“I don’t see any evidence of a loss of appetite for long-term contracts,” Bounds said.
The buyers bite back Speakers from the buyers’ side of the LNG market had little to say about the length of contracts.
But everything else about their customary way of doing business seemed to be up for discussion.
They had a booster in Maria van der Hoeven, executive director of the International Energy Agency.
Buyers and sellers have a shared interest in a flexible, efficient and competitive LNG market in Asia, she said. “That means saying ‘no’ to some of the status quo of today.”
LNG buyers took shots at two targets in particular throughout the conference:
•Destination clauses that lock in LNG cargos to unload at specific ports and only those ports.
•Today’s norm of LNG prices in Asia linked to oil on an approximate energy-equivalent basis.
Van der Hoeven took shots at them, too. They both must go away, she said.
LNG producers would be wise to recognize that restrictive destination clauses are headed for extinction. An LNG producer that hesitates to remove them from sales contracts delays the inevitable and risks losing market share to nimbler competitors, Van der Hoeven said.
Some destination flexibility exists in today’s market, spurred in part by a ban on the clauses for cargoes delivered to Europe. But Mateille of Total and Bounds of Shell noted that another factor is creating additional flexibility for some LNG cargoes: the rise of so-called portfolio players. These are companies such as Total, Shell, BP and BG Group that have access to LNG supplies from a variety of plants around the world and have contracts to deliver to a variety of customers. The companies can mix and match LNG supply and customers to optimize their portfolios.
As for oil-linked prices, Asia must develop the mechanisms of an efficient and transparent gas market so that the gas market can set prices, not the oil market. These mechanisms include trading hubs and third-party access to infrastructure. All this will take time, Van der Hoeven said.
Multiple speakers, from Japan, Taiwan, South Korea, India and the United States endorsed the concept of developing an Asia gas market that could become the basis of a new way to price the fuel in Asia.
It was clear, however, that such a market is a long way from reality, although initial steps have begun. Singapore has built LNG storage and some traders have set up shop in that nation. In 2013, Shell moved its LNG headquarters to Singapore from Europe.
In 2014, the Tokyo Commodities Exchange started an over-the-counter market for LNG to try to stimulate buying and selling outside of traditional contracts. About 20 trading firms or utilities are signed up, said Tatsuya Terazawa, who is in charge as Japan’s director-general for commerce, distribution and industrial safety policy.
The effort is just seven weeks old, and it’s not clear that any trades have actually occurred. Mateille of Total said he hears the marketplace is all buyers and no sellers.
But Terazawa said the long-term aspiration is big, hoping that the market will involve many more traders from Japan and elsewhere and set a benchmark LNG price that’s meaningful to the larger Asia market. Eventually - soon, Terazawa said - a futures market will roll out, allowing LNG traders to hedge against price risks.
Falling oil prices The recent plunge in world oil prices was background noise at the conference, without any revelations about how long the price slump will last or what the drop might mean for oil-linked LNG prices.
Oil has fallen from about $100 a barrel at the end of August to around $80 now.
Bounds of Shell noted that LNG prices adjust to oil prices on a time lag. The break to LNG buyers paying oil-linked prices mostly will show up next year, he said.
Besides, the lower price should remind LNG buyers that oil-linked prices can have value, too, he said. U.S. natural gas prices have fallen about half as much in that same time span.
Coleman of Woodside Energy said some more expensive LNG projects have negative free cash flow at $90 or $100 oil prices. So the low price can be a strain. But he also was sanguine about the drop, saying, “The industry will go through this natural cycle.”
Mateille of Total said North American exports to be sold in Asia at U.S. gas prices plus liquefaction and shipping costs would be cheaper than oil-linked prices when oil costs more than $80 a barrel. If the oil price keeps falling to $70 or $60, the classic oil-linked contract will look very good to Asian buyers, he said.
Editor’s note: This is a reprint from the Office of the Federal Coordinator, Alaska Natural Gas Transportation Projects, online at www.arcticgas.gov/print/lng-sellers-asian-buyers-talk-differences-tokyo
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