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The Challenges Facing Alaska LNG Exports


The logistics of getting natural gas from Alaska to Asian buyers are relatively straightforward. About 800 miles via pipeline from the North Slope to tidewater somewhere in Cook Inlet or maybe Valdez. Liquefy the gas, load it aboard tankers, then 3,400 miles by sea to Japan. Or a little farther to China. Pretty simple to draw the lines on a map.

The tanker route from Alaska to Japan is half the distance as the route from the Middle East, and it’s two-thirds shorter than the distance from proposed liquefied natural gas export terminals on the U.S. Gulf Coast. (It’s about the same from Australia as it is Alaska.)

A round-trip from Alaska to Japan would take about 20 days. Longer trips cost a lot of money. LNG charters were running as high as $150,000 a day in the spring, though long-term charters were less.

The relative proximity of Alaska to Asian buyers provides the easy numbers that work in favor of an Alaska project. But competition from other LNG suppliers, construction costs, operating costs and commodity pricing — those are the tough numbers.

Eyeing Japan and China

Alaska once had the Japanese LNG market all to itself. That was 43 years ago, when the liquefaction plant at Nikiski inaugurated the trade for shipping liquefied gas to the Pacific Rim nation. But since then, 16 other countries have gotten into the business of selling gas to Japan. Alaska’s share of the market in 2011 was 0.5 percent.

“The country has a fairly balanced portfolio, with no one supplier having a market share greater than roughly 20 percent,” according to a U.S. Energy Information Administration analysis of Japan’s energy needs. LNG deliveries last year came in from Southeast Asia (Malaysia, Indonesia, Brunei), the Middle East (Qatar, United Arab Emirates, Oman, Yemen), Africa (Algeria, Egypt, Nigeria, Equatorial Guinea), Russia, Australia, Norway, Trinidad and Tobago, Peru and Alaska.

China, another Asian growth market of interest to Alaska LNG proponents, last year accepted deliveries from 11 countries. But unlike Japan, China has significant domestic production and a pipeline option – it took almost as much natural gas via a pipeline from Turkmenistan last year as it did via LNG tanker.

Guy Broggi, senior adviser at the LNG division of Total Gas & Power, part of the French oil and gas major Total, is skeptical that China will be buying as much LNG as some predict. Instead, the nation will load up on less expensive pipeline gas from Turkmenistan, Myanmar, maybe even Russia, Broggi said at an LNG conference in Houston in May.

“China will not be the one to take the highest price,” Broggi said.

Another issue for China is that the government sets the price companies can charge for gas, keeping it low to aid consumers. But that means importers, such as utilities, lose money on the fuel. China has embarked on a pilot project to allow buyers to charge up to $12 per million Btu for gas — more than twice the current subsidized rate and near the actual cost — though it’s too early to know how consumer demand will respond if people have to pay close to the real value of the fuel.

And though demand is growing in China, it is a small market: A full day’s worth of LNG in China last year would have lasted about half an hour with U.S. consumers.

An Asia-market plus for Alaska, however, is that many of Japan’s LNG supply contracts, with extensions, date from the 1970s and 1980s and will expire over the next decade, pushing buyers to negotiate new deals. Of course, suppliers in those 16 other countries that sent gas to Japan last year are thinking the same thing, as are new players coming to the market.

A Boom in LNG Projects

About $200 billion in projects under development in Australia and Papua New Guinea are on schedule to add more than 9 billion cubic feet of gas per day to the global LNG supply capacity by 2016. These projects will provide almost 30 percent more capacity than LNG buyers consumed worldwide last year.

And rather than depending solely on others to sell them gas, Japanese utilities, oil and gas producers and trading companies are getting into the business themselves. They own stakes in five Australian LNG export projects — one that went online this year and four others under or ready to start construction. They also hold equity shares in operating and proposed projects in Russia, Indonesia and Canada, plus several more gas plays worldwide that could develop into LNG export operations.

Meanwhile, the next wave could come from the East African nations of Mozambique and Tanzania. Anadarko Petroleum, Italy’s Eni and Norway’s Statoil and partners have discovered more than 100 trillion cubic feet of natural gas in reservoirs offshore these nations. Gas from these discoveries could find its way aboard LNG tankers in the next decade.

Economic growth in China and India, along with permanent closure of Japan’s nuclear power plants, could create enough demand to take all that gas, including Alaska’s. Or not.

Among the unknowns are how fast China’s economy will grow, how quickly it will develop its own shale gas resources, how much more gas will be piped from Turkmenistan and possibly Russia, and how many nuclear plants go back online in Japan. These unknowns are key risks facing developers of LNG projects.

LNG Price Another Unknown

Price for LNG is another risk, an especially important one for capital-intensive projects such as liquefaction terminals. International energy research firm Wood Mackenzie last year estimated a liquefaction plant and export terminal at Valdez, capable of sending out an average 2.7 billion cubic feet per day, could cost about $24 billion. The 800-mile pipeline from the North Slope and tankers would be additional.

Wood Mackenzie estimated liquefaction would add about $4 per thousand cubic feet to the price of LNG from North Slope gas, plus production, gas treatment, pipeline and tanker charges. A smaller Alaska LNG project likely would encounter higher liquefaction costs — losing the economies of scale.

It adds up to the reality that it would take high LNG prices to pay off the debt and recover the investment on an Alaska project.

Asian buyers of LNG — particularly Japan, with no pipeline option — over the years have been willing to pay high prices. But with so many new suppliers coming to market, there has been wide speculation that Asian buyers will use the opportunity to break the traditional Btu-equivalent link between LNG and oil prices.

With world oil prices moving between $100 and $120 a barrel for the first half of the year, LNG spot-cargo prices in Japan have been between $15 and $18 per million Btu (roughly 1,000 cubic feet), with long-term contract prices a little lower.

Tokyo Electric Power Co. is considering buying North American shale gas starting in 2016 as it looks to lower its fuel costs. A Japanese business newspaper reported the utility believes it can buy U.S. shale gas at half the price it pays for oil-price-linked LNG deliveries.

“The link to the crude-oil price is no longer that reasonable, so we need to break that linkage,” said Mitsunori Torihara, chairman of Tokyo Gas and the Japan Gas Association.

An erosion of oil-linked pricing is possible as new projects come into the market worldwide, said Mark Habib, a director with Standard & Poor’s energy team. “The supply response could be quite significant … and help erode the link to crude,” Habib said at an LNG conference in Houston in May.

North American Competition?

Buyers are looking to potential lower-cost supplies from North America — which is awash with shale gas production and reserves — to put pressure on high prices in Asian markets. But there is some political and consumer opposition in the United States to sending natural gas overseas, and that uncertainty worries Asia buyers who value certainty of supply.

The U.S. government has given its full approval to just one export project, with eight others on hold pending further studies of how exports could impact U.S. natural gas prices and the nation’s economy. No decisions are expected until later this year, at the earliest.

Cheniere Energy’s proposed export terminal at Sabine Pass, La., is the only new U.S. project to have full regulatory and export approvals in hand. It has gas buyers under contract in 20-year deals linked to the U.S. natural gas benchmark price (Henry Hub, La.), meaning LNG could be delivered to Japan at under $9 per million Btu at today’s U.S. gas prices — liquefaction and shipping included in that price. That price looks appealing to buyers in Asia today.

Korea Gas has signed up to buy an average 500 million cubic feet of gas a day from Cheniere’s proposed terminal starting in 2017.

But what about the future for LNG pricing? Bet on world oil prices, or bet on U.S. natural gas prices?

“We can’t be certain where Henry Hub will be in five years, much less 20 years,” David Lang, a Hong Kong-based partner specializing in China and energy transactions and projects at law firm Vinson & Elkins, told the LNG conference in Houston. Contrary to today’s rock-bottom prices, Henry Hub soared above $10 per million Btu in December 2000, February 2003, fall 2005 and summer 2008.

“Long-term contracts are for 25 years or so, and betting gas prices will remain low for 25 years is a big gamble for consumers,” Hamad Rashid al-Mohannadi, managing director of RasGas, Qatar’s second biggest LNG producer, said June 6 at a gas conference in Malaysia.

Alaska’s competition for LNG buyers also includes Canada. There are trillions of cubic feet of shale gas in northeastern British Columbia, with producers Shell, Encana, Apache and others looking to bring the gas to tidewater at Kitimat, B.C., liquefy it, and grab a piece of the Asian market.

Pricing will be an issue for Canadian projects — oil-linked or gas-linked — as will the fact that the B.C. projects will bear the extra costs of developing the gas fields and building pipelines, storage tanks and docks. U.S. Gulf of Mexico projects already have most of that in place. Many of them propose simply adding liquefaction capabilities to existing U.S. LNG import terminals.

That head start puts U.S. projects at an advantage to Canadian proposals, said Bevin Wirzba, a Calgary-based managing director at RBC Capital Markets.

Fighting Over U.S. Exports

Korea Gas Corp., the world’s single biggest importer of liquefied natural gas, believes U.S. politics will determine how much LNG the country is allowed to export and whether those shipments will undermine the 40-year-old oil-linked price mechanism used in Asia.

It is not alone in that belief.

“There is a lot of lobbying in the U.S. to limit LNG exports and to instead use the gas to allow the domestic industry to benefit from low energy prices,” said Jayesh Parmar, of Baringa Partners, a London-based management consulting firm that focuses on energy issues.

Industrial lobbying in the United States is likely to put a cap on potentially huge natural gas exports, benefiting domestic industries such as petrochemicals and power generation but limiting export profits from gas-hungry Asia and Europe, Parmar said. “Petrochemicals and refined products, as well transportation industries that use natural gas, stand to gain from such a policy.”

Those are fighting words to others.

“It would be political suicide to try to stop it (exports),” said Barry Worthington, executive director of the U.S. Energy Association. The main opponents to exports, he said, are environmentalists who link it to hydraulic fracturing and shale gas production, and large gas customers that want to keep U.S. prices low.

The political battle may not matter much for Alaska. Because it is not connected by a pipeline to Lower 48 markets, opponents couldn’t argue that shipping Alaska gas overseas would deprive U.S. buyers. An Alaska export project still would require federal approvals, though they could prove much less controversial than Gulf Coast or East Coast terminals. R

Larry Persily is Federal Coordinator for Alaska Natural Gas Transportation Projects. Persily, who was appointed by President Barack Obama in December 2009, served almost 10 years with the Alaska Department of Revenue, governor’s office and as a legislative aide on oil and gas issues before taking a turn at federal service. He previously worked as a newspaper reporter, editor and owner in Alaska for almost 25 years.

This article first appeared in the August 2012 print edition of Alaska Business Monthly magazine.
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