LNG producers and consumers talked — and pushed, but did not shove — at a Tokyo summit Sept. 10 that the Japanese government called to continue the dialogue over high liquefied natural gas prices that are straining its economy.

Kickoff remarks from two heavyweights in the world’s LNG economy framed the dialogue.

The first came from Toshimitsu Motegi, economy, trade and industry minister for Japan, the world’s largest LNG consumer. A buyers’ market looks to be coming, Motegi suggested. Buyers will be buoyed by more LNG supply and new sellers. LNG plants currently under construction will raise global output 30 percent by 2018, he said.

Add to that the potential volumes from proposed export plants in the United States and such new frontiers as Western Canada, East Africa and Russia, and total global output could reach 600 million metric tons a year, roughly 80 billion cubic feet a day — more natural gas than the United States and Canada consumed in 2012. That much LNG — and that many new suppliers — all seeking customers will give buyers the nirvana they seek: A stable supply of competitively priced LNG, Motegi said.

But squaring up to answer Motegi strode Mohammed Bin Saleh Al-Sada, minister of energy and industry for Qatar, the world’s largest LNG producer. Demand has always outpaced supply, not the other way around, during the 50-year history of LNG trade, he observed. This will remain true as China and India gulp more LNG, as new consumers emerge in Southeast Asia, the Middle East and elsewhere, he said.

“Gas prices will remain regionalized for the foreseeable future,” he predicted. Exports of abundant North American shale gas production as LNG will be too small to change the game and meaningfully shake up oil-linked Asian and European gas pricing structures. To believe otherwise is to be “over-optimistic,” Al-Sada said.

Motegi of Japan and Al-Sada of Qatar delivered the opening keynote speeches of the 2nd LNG Producer-Consumer Conference, a one-day event sponsored by Japan’s Ministry of Economy, Trade and Industry and the Asia Pacific Energy Research Center.

2012 conference ‘wowzer’

The first conference in September 2012 was a wowzer. LNG buyers told sellers they thought they were being cheated on price; that supply-and-demand fundamentals could not explain or support the stratospheric prices they paid; and that the fundamental relationship between LNG makers and their customers needed to change.

The 2012 message was the LNG marketplace’s shot heard around the world. The topic has reverberated in contract negotiations, at conferences and just about anywhere else LNG has been discussed during the 12 months since.

The second annual conference Sept. 10 was an effort to keep the conversation going ... and keep it public. From remarks of participants this year, a third conference next year is likely.

Voices from just about every region in the LNG constellation were represented on the dais at some point during the day, except for China and South America.

LNG buyers in particular remained feisty and adamant that change must come.

Producers reiterated the cold-hard-cash fact that multibillion-dollar LNG projects are brutally expensive to build. With most of this spending up-front, they need long-term customers paying high enough prices to provide confidence they will earn an adequate rate of return on that investment.

But beyond those broad positions, it became clear at the conference that the buying and selling of LNG in 2013 is evolving from the norm of just a few years ago, when almost all LNG sales occurred under 15- to 20-year contracts that required deliveries of the cargoes to a fixed destination and nowhere else in the world, and that dictated a price tied somehow to oil prices.

Today, the norm remains long-term contracts at oil-linked prices, if only because so much trade is occurring under contracts already in place under those terms.

However, more short- and medium-term contracts are getting signed, more spot-market sales are occurring, more sales prices have severed the link to oil in whole or in part, and more cargoes are less restricted to fixed destinations, allowing LNG tankers to sail to where the gas is needed — such as Japan after its nuclear-power shutdown — or where the price is better — such as in Asia instead of North America or Europe.

It also became clear at the conference that LNG buyers and sellers have been hearing each other during the past year.

Some sellers, while maintaining their need for a price that provides an adequate return for the investment risk, seemed less locked in to an oil-linked price as the only approach. However, oil prices have the advantage, they noted, of being transparent in an actively traded global marketplace of multiple buyers and sellers, unlike the much smaller LNG market.

And some buyers are acknowledging that if oil-linked prices fade as the standard, they cannot let sellers bear all the risks of that change.

Change comes in steps

In the days just before the conference, several announcements gave evidence to the changes under way as LNG buyers and sellers try to write new rules for their future:

Japan and India set up a multilateral LNG buyers group to collectively seek lower prices. They will ask other buying countries to join. “LNG prices in Asia are substantially higher than those in other major consuming regions such as Europe and North America,” the two nations said in a joint statement.

Japan and India also agreed to jointly study solutions to high LNG prices. “The study is an important step towards working on rationalization of LNG prices in Asia-Pacific,” the countries’ top energy ministers said. Masakazu Toyoda, CEO of the Institute of Energy Economics Japan, which hopes for a role in the research, told the conference the study could identify pathways for joint procurement of LNG, joint upstream investment and joint efforts to create an Asian LNG pricing hub, any and all of which could improve the buyer-seller dialogue about a win-win future.

The Japanese government plans to reform its regulation of gas-buying utilities to cut their thirst for LNG. Takayuki Ueda, director general of Japan’s Agency for Natural Resources and Energy, told the conference that a series of steps through 2020 will streamline the nation’s fragmented power generation and transmission structure, debundle these services to make them more competitive and efficient, and end utilities’ ability to pass through to consumers the prices they pay for LNG. Instead, the regulated price will be the lowest price of gas, and companies will need to get lean to make that work.

Freeport LNG Development signed up Japan’s Toshiba Corp. and South Korea’s SK E&S LNG to take production for 20 years from a third 4.4 million metric ton per year (almost 600 million cubic feet a day) LNG production train the company proposes to build at its Texas export terminal. Freeport already has long-term contracts with Chubu Electric and Osaka Gas of Japan and BP for 8.8 million tons per year (about 1.2 billion cubic feet a day) from two other trains at the proposed plant. Like other expected U.S. Lower 48 exports, this LNG won’t have oil-linked prices, and the cargo destinations will be up to the shippers, not fixed. Instead of oil linkage, prices will be based on the U.S. Henry Hub gas price plus liquefaction and shipping costs.

Japan also is moving to get more nuclear power generation back online. The nation’s annual LNG imports have jumped 20 million tons (more than 2.5 bcf a day), or 25 percent, since 2010, said Motegi, the energy minister. Coal and oil imports grew as well after the March 2011 earthquake and tsunami knocked out nuclear power. More nuclear restarts promise to cut Japan’s LNG imports by 10 percent in 2014, said Toyoda of IEEJ.

Besides these moves, a demographic factor could erode Japan’s LNG demand, said Takayuki Sumita, resources and fuel department director general for Japan’s Agency for Natural Resources and Energy. The population is aging and will shrink, he said.

Twenty years from now, Japan might be importing less LNG due to all of these changes, Toyoda said.

That’s the future. The present for Japan involves sobering trade deficits as the country imports more high-priced fossil fuel to replace nuclear power. In 2011 — the earthquake/tsunami year — Japan endured its first trade deficit since the early 1980s’ global oil-price shock. The deficit grew in 2012, and in the first half of 2013 it reached a record $48.7 billion.

Economics say that if you buy a lot you should get a price discount, said Naomi Hirose, president of Tokyo Electric Power. But that didn’t happen.

“We learned in economics that price differences will disappear with a lot of transactions,” he said. That also didn’t happen.

To get more control of its own fate in the LNG world, Hirose said, TEPCO will acquire more upstream equity in natural gas or LNG production, giving it the option to ship gas to itself. TEPCO is getting tough to remove destination clauses from its purchase contracts, buying LNG from more parts of the world and revamping its infrastructure so its turbines can burn liquids-rich gas from Indonesia or dry methane from the United States, he said.

If rich gas is more expensive, TEPCO will have the flexibility to buy lean gas, and vice versa, he said, just as it did back in the days when oil and gas were substitutes. “We have to be ready to accept that.”

Crazy high costs

An ironic twist in the Asia buyer-seller push-pull is that some sellers have been complaining about prices, too — that they are too low.

In recent months, Yemen has told South Korea that it wants to renegotiate the sales price upward for its LNG cargoes. Indonesia’s Tangguh operation has been saying the same to China, and Australia’s Pluto owners want higher prices from some buyers. Some of the LNG from the three projects is being sold under old contracts at low prices — between $3.50 and $8 per million Btu.

How could this be? Some insight comes courtesy of Singapore, a new LNG importer as of 2013 and a nation that hopes it can build enough spare storage capacity so that it can become a re-export, bunkering and trading hub, something Asia lacks.

At the conference, Lee Seng Wai, director of gas policy and infrastructure development for Singapore’s Energy Market Authority, said his agency’s research shows that timing — signing a contract during a buyers’ market vs. a sellers’ market — is a bigger key to price than the volumes purchased.

The pricing message from LNG producers was sharp: We’re in a crazy-high-cost business and we need to be compensated for the investment risks we undertake if you want us to build more LNG plants.

Annual LNG demand will exceed 600 million tons by 2040 (80 bcf a day) and 40 countries will be importing the fuel, triple the number of 2005, said Rob Franklin, president of ExxonMobil Gas & Power Marketing.

The costs of building LNG export plants have been soaring — escalating faster than even the cost of LNG prices, he said. Long-term commitments from buyers are a must. Another must: Tight government and investor alignment throughout the value chain to help projects come together more easily and cost-effectively, he said.

Liquefaction costs have doubled since 2006, noted Joseph C. Geagea, president of Chevron Gas and Midstream. The average project takes 18 years from discovery to first LNG output, he said. The vast scales of cost and time are part of what make LNG a business dominated by government oil companies and international oil firms like Chevron and ExxonMobil.

“Henry Hub-linked prices are no guarantee of low prices,” Geagea said. Historically, Henry Hub gas prices have been much more volatile than oil prices, he said.

The Henry Hub and the United Kingdom’s National Balance Point gas-price indexes may be getting loving looks from Asian gas buyers today because they’re so much lower than the oil-indexed price. But indexing LNG to Henry Hub and NBP could expose Asia to unjust price volatility, echoed Philippe Sauquet, president of gas and power for French oil giant Total.

“Oil index doesn’t (always) imply high prices,” Sauquet said.

“Henry Hub is a spot price for marginal volumes” in the United States, said Martin Hoffman, Australia’s deputy secretary of the Resources, Energy and Tourism Department. A Henry Hub-based pricing formula is not a reliable 15-year framework for prices, he said.

Sauquet of Total noted suppliers are competing for buyers, which has given rise to a variety of contract types: long-, medium- and short-term, blended price formulas, destination flexibility. There is room to negotiate key issues, he said.

Risk goes two ways

Some conciliatory language did get sprinkled into the remarks of LNG buyers as well.

“We will not say we will not take any (price) risk. That is not acceptable,” said Tsuyoshi Okamoto, president of Tokyo Gas.

“Risk and reward must be shared,” said Bhuwan Chandra Tripathi, chairman and managing director of The Gas Authority of India, GAIL, that nation’s largest gas-distribution company. But GAIL has taken risks of its own by investing in LNG receiving terminals and regasification infrastructure, he said. And it faces risks of more volatility from new or hybrid pricing formulas. (GAIL will buy LNG at Henry Hub prices plus liquefaction costs from Cheniere Energy’s export plant under construction in Sabine Pass, La.)

GAIL is willing to sign long-term take-or-pay contracts that require it to buy certain volumes from an LNG plant. “But let me choose the destination,” Tripathi said.

But generally, buyers talked tough.

The initial pegging of LNG prices to oil was justified 30 years ago because oil and gas were very close substitutes, said Han Jinhyun, South Korea’s vice minister for trade and energy. That logic has become irrelevant in today’s market. And destination clauses prevent freer trade.

“It’s time for change,” he said. “Those who cannot change their minds cannot change anything.”

The transition away “from oil-linked prices must become a necessary condition for sellers to sell in Asia,” said M. Veerappa Moily, India’s minister of petroleum and natural gas.

The LNG price that many sellers are seeking in Asia is far above the extra cost of transporting gas there from other regions. Moily called it the “Asia premium.” This premium places “an unreasonable burden” on buyers that ultimately will hurt sellers, too, when buyers get their energy elsewhere, Moily said.

Asia needs to create a reference price that reflects the forces of demand and supply, plus the transportation cost of moving LNG to market, he said.

Neutral voices

The conference wasn’t all about butting chests.

An entire session was devoted to LNG’s possible new production frontiers.

Dan Sullivan, Alaska’s commissioner of natural resources, pitched his state’s efforts to push ahead on two projects that could deliver LNG — one in massive volumes and the other in smaller volumes. Sullivan reiterated the Alaska advantages he recited at last year’s conference: A short shipping route to Asia that isn’t infested with pirates or other perils; proved and developed gas reserves at Prudhoe Bay; a 43-year track-record of reliable deliveries from the now-shuttered LNG plant at Nikiski; and isolation from the politics of Lower 48 LNG exports.

Other pitches were made for British Columbia, Mozambique and Vladivostok, Russia.

And some relatively neutral voices weighed in on the LNG buyer-seller dispute.

“There isn’t an Asian premium,” said Steve Hill, vice president of global LNG and oil marketing for BG Group. North America and Europe are releasing unneeded LNG to Asia and South America. This is holding down the LNG price outside of Asia and South America, accounting for the price gap that Asia buyers cite, Hill said.

U.K.-based BG Group is a newer breed of player in the global LNG business. It’s a so-called portfolio player. It buys LNG from many sellers. It sells LNG to many buyers. Most of its contracts do not dictate which plant will supply the gas or which buyer will get it. BP is developing a similar portfolio play in LNG, as are other companies.

Hill said BG has looked at all the demand-supply forecasts and sees a consensus: The world will need 150 million tons a year more LNG (about 20 bcf a day) by 2025 than is under construction. Demand could be even greater than that if supply could keep up, he said.

The worst situation that could happen to the industry would be projects stalling around the world while developers wait to see how much LNG gets exported from the United States and Canada, Hill said.

R.A. Walker, chairman, president and CEO of Anadarko Petroleum, said his company hopes to decide next year to build an LNG export project to monetize its new discoveries offshore Mozambique. He said his company and others are finding so much gas there that Mozambique could become the world’s No. 3 LNG exporter in the next decade — behind Australia and Qatar.

So, what does he think, will a move away from oil-linked pricing toward the Henry Hub or other gas index hurt Mozambique’s chances?

“I’m agnostic. We don’t have oil-linked contracts now,” Walker said.

“We want a price that gives an attractive rate of return for the risks we took,” he added. That “formula” will be a win-win for buyers and sellers. “We’re not looking for a windfall.”

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