Editor's note: This article is written for publication by a federal agency whose goal is to transparently coordinate permitting and construction of a pipeline that delivers Alaska's natural gas to the Lower 48.
The global liquefied natural gas industry has been marked in recent years by a multibillion-dollar build-out, new suppliers, fresh markets, a new dominant player and an emerging rival.
In the last five years, the volume of LNG available on the market has jumped 50 percent, a growth rate that's three times faster than the overall growth of world gas production.
Qatar, with a mighty 900 trillion cubic feet of gas reserves, swept Indonesia off the LNG production throne as the new industry leader in output during this period.
Norway entered the competition with its first LNG exports in 2007. Yemen got in the game in 2009, as did Russia that year with its Sakhalin 2 development. Peru became an exporter last year.
The stampede to open or expand liquefaction plants involved 23 LNG plants around the world, with 16 of them located in Asia or Australia.
A new International Gas Union survey of the LNG industry lists 14 more LNG projects under active development - eight in Australia and three others nearby. Australia could leap over Qatar as the leading LNG producer within 10 years.
LNG demand has kept up with supply for obvious reasons - all that LNG went out and found buyers. LNG's percent of world gas consumption - its market share, in business school parlance - jumped to 9 percent last year from 6 percent in 2000. The rest, 91 percent of the world's gas output, moved to market via pipeline last year.
But this story line of breathtaking growth is not all a tale of successes and smiles.
The story is also a tale of big bets on U.S. LNG demand that never materialized thanks to a wildcard that no one saw coming - the rise of Lower 48 shale gas production.
A shale gas curveball
Global capacity to produce LNG has grown even faster than the remarkable growth in LNG volume sailing around the globe on special tankers.
In fact, while demand grew by 10.7 billion cubic feet a day in the past five years, the capacity of new and expanded production plants grew by 14.4 bcf a day. An additional 8.8 bcf a day of production capacity is under development, according to IGU figures. The LNG tanker fleet has grown even faster, IGU reports.
This means many LNG plants are producing far below their capacity. And that has tossed topsy-turvy how LNG is bought and priced. A decade ago the industry was defined almost exclusively by LNG importers signing long-term supply contracts. That world has shifted to one in which LNG shipments increasingly are bought on the spot, or short-term, market. Further, the historic link of LNG prices to oil prices is weakening.
Why has so much overbuilding occurred? The answer centers on the rise of Lower 48 shale gas production.
Much of the LNG capacity growth came from exporters salivating to serve what in the mid-2000s looked like a rapidly widening gap between U.S. gas consumption, which was rising, and U.S. production, which was falling from conventional fields. This is the same gap that revived plans to build the major pipeline to move gas from Alaska's North Slope to Alberta and on to the Lower 48 states.
Instead of widening, the gap has stabilized and the U.S. Energy Information Administration forecasts it to remain stable or even shrink over the next decade.
The swift rise of shale gas has transformed much about the North American gas industry:
- The supply glut has softened gas prices.
- Drilling rig owners are scrambling to keep up with business.
- New pipelines are being planned.
- Existing transmission pipes that flowed south are now flowing north, and some flowing east will be piping gas west.
- Power plants, a big consumer of gas, are tilting their fuel supplies in favor of gas over coal.
- U.S. LNG-import plants are seeking permission to retool and export in addition to still accepting imports - that way, they can play both markets. (No plant has all of its export and regulatory approvals, financing and customers as yet.)
- Investors in Canada, the top supplier of foreign gas to the Lower 48, think building LNG-export plants in British Columbia will give them a new outlet for gas they no longer will pipe south.
- Dozens of foreign nations are wondering about their own shale gas possibilities.
The hydraulic fracturing technique the industry uses to pry gas from shale also has sparked new scrutiny from skeptical environmentalists, alarmed community activists, harried regulators and cautious lawmakers.
"In North America, the global LNG question has been reframed for the second time this decade," says the Canadian Energy Research Institute in a new report on gas-industry trends.
"Earlier in the decade, the dominating concern was whether or not the North American market would be able to import enough LNG to supplement declining domestic natural gas supplies in order to meet the expected growth in natural gas demand. The list of proposed LNG import terminals in North America ballooned, reaching over 40 projects, in anticipation of the growing LNG demand."
But late in the decade it became clear that shale gas had stolen away the market LNG importers eyed. This also was bad news for the "global liquefaction projects, which were constructed in anticipation of a robust North American LNG market," CERI says.
"In 2009, the U.S. began re-exporting foreign sourced LNG, with the first two cargoes transported to South Korea. In 2010, seven countries (the United Kingdom, Spain, Belgium, Brazil, South Korea, Japan, and India) received re-exported LNG from the U.S. (Re-exported gas arrives in the U.S. from a foreign LNG plant and then is shipped away again rather than used in the United States.)
"The North American natural gas industry is now pondering a new question - can North American natural gas be competitive in the global LNG market?"
The International Gas Union in its new report paints a similar picture:
"A significant source of demand for global LNG supplies has disappeared. Given that LNG investments have a long lead time, there is a significant amount of LNG capacity that is coming online between 2009 and 2012 which was constructed based on the market expectations of 2005, whereby the U.S. would become a major import market.
"This LNG had to find a new place to go - and in 2010 it found a home mostly in Europe as well as in emerging markets (Middle East and Latin America)."
The LNG supply glut is causing more LNG importers to buy on the spot market, which has grown to over 20 percent of the purchases, the IGU says. Spot market prices in Europe are now far lower than those in long-term contracts that link LNG to a percentage of oil prices. In Asia, spot prices are higher, due in part to Japan's need to import more LNG after its nuclear power plant disaster this year.
The IGU poses the big question: "If one excludes the U.S. as an importing country, does the global supply and demand balance tighten sooner or later?" The answer is unknowable.
Forecasting misfires
How badly did some prominent forecasters misfire on U.S. LNG demand?
First, two reference points.
Last year the United States imported an average of 1.2 bcf a day of LNG, according to the Energy Information Administration. U.S. imports peaked four years ago - 2.1 bcf a day.
Now here are some old forecasts:
- Consultant Wood Mackenzie in 2007 - the record year for U.S. LNG imports - predicted imports would grow to 15.9 bcf a day in 2025.
- The EIA in 2007 was more conservative - predicting 12.3 bcf a day of LNG imports by 2030.
- In 2008, as the shale-gas revolution became visible, the EIA shaved its estimate down to 7.7 bcf a day in 2030.
Last April, the EIA offered its latest estimate for 2030 LNG imports: 0.4 bcf a day.
Alaska LNG ideas
This is the environment - rising LNG demand, prices in flux, capacity overbuilt, more capacity coming - that backers of an Alaska North Slope-to-Valdez LNG project would enter.
A new report done by Wood Mackenzie for one of those backers - the Alaska Gasline Port Authority, a joint venture of the local governments in Valdez and the Fairbanks borough - says Valdez LNG could be cost-competitive with those being discussed for Australia and British Columbia.
Yes, Alaska would need a pipeline project, Valdez liquefaction plant and tanker port that together could cost as much as $49 billion - more than any other LNG project going. Tankers would cost extra, at an estimated $200 million each.
But, the report says, this staggering cost is offset by the fact that the key gas field - Prudhoe Bay - already is developed; the gas there that rises up oil wells mostly is injected back into the field. Some nearby oil fields also hold some gas. However, the North Slope's No. 2 gas field - Point Thomson, 60 miles east of Prudhoe Bay - hasn't been developed, and its gas production costs will be significant.
The Wood Mackenzie report estimates Valdez LNG would be profitable as long as oil and LNG prices remain strongly linked. Specifically, oil prices must stay above $75 per barrel and gas prices at least $9.75 per million Btu - or 13 percent of oil, Wood Mackenzie says. The long-term contract price lately has been around $12, according to the publication Natural Gas Week.
A big drawback of the Valdez idea: It would produce 17 million to 19 million metric tons of gas annually, or more than 2.5 bcf a day on average.
No other single LNG project ever constructed anywhere in the world produces even half what a Valdez plant would, although Qatar built about 50 million metric tons of capacity total in multiple projects.
It's unclear where Alaska would find buyers for all that LNG. The Valdez output of 2.5 bcf a day compares with current global LNG demand of about 29 bcf a day. Although LNG demand is growing, existing plants have capacity to produce about 36 bcf a day and can meet that growth for a while. Projects already under development expect to lift LNG production capacity to 45 bcf a day by 2015.
An inability to sell 100 percent of the Alaska LNG soon after start-up would shake the Valdez project's economics. The alternative being pursued for Alaska gas would pipe it to the Lower 48, where far more gas is consumed than in the entire worldwide LNG market, although the market price there is much lower than the Asia LNG price today.
Sponsor of the Alaska-to-Alberta pipeline project - a partnership of TransCanada and ExxonMobil - also proposed a Valdez route during its open season last year. But based on its filings with the Federal Energy Regulatory Commission, the partnership found too little interest in the option to continue pursuing it for now.
Still, as was seen in forecasts of U.S. LNG imports, there is no shortage of economists willing to offer their best guess of the future. Canada-based consultant Ziff Energy recently predicted Asian LNG demand would grow by 26 bcf a day in the next nine years, Natural Gas Week reported in August.
What LNG is
Liquefied natural gas is what the name implies - regular natural gas in liquid form rather than gaseous.
Special plants super-chill gas to minus 260 to make it liquid and more dense so it can be stored in smaller spaces. This makes it more cost-effective to ship across seas via special tankers when no pipelines are available or practical.
At the import destination, another plant receives the LNG and converts it back into gaseous form for piping to power plants and other consumers.
The LNG fleet, by the way, underwent an even greater growth spurt than the LNG plant building binge. In the 1980s and 1990s, shipbuilders launched an average of four new LNG tankers per year. But the average was 35 a year from 2006 through last year, with a record 47 tankers christened in 2008, the IGU says. A typical tanker can carry 3 bcf to 6 bcf.
LNG's tragic beginnings
The LNG industry got a sad start during World War II.
A Cleveland utility built the first commercial LNG plant in 1942 to store gas for use by local war industries.
The experiment was a disaster, literally. An explosion and fire in 1944 scorched more than a square mile of Cleveland homes and businesses, and killed 130 people. That snuffed the industry for years.
In the late 1950s, tinkering with LNG revived, including devising a way to move LNG in ocean-going vessels. In 1959, a pilot project shipped LNG from Louisiana to England.
The first and so far only U.S. commercial exports have come from a Nikiski, Alaska, plant that opened in 1969, processing the new discoveries of Cook Inlet gas. Phillips Petroleum Co. (now ConocoPhillips) and Marathon Oil Co. were partners in what then was the world's largest LNG project - and the biggest project of any kind that the two companies had ever tackled. The plant supplied two utilities in Japan with gas under long-term contracts. That 42-year-old plant was expanded several times but now is slated to close this fall due to difficulty securing reliable supply.
Betting on an LNG future
As was said, LNG suppliers have kept pace with demand, in part thanks to having plenty of capacity.
Importers also are drowning in capacity.
Last year, five new LNG receiving terminals started up, bringing the total to 83 in 22 countries, compared with 18 exporting countries, according to IGU data.
The 83 terminals can receive and regasify 75 bcf a day of LNG. How much overcapacity is there? Last year an average of 29 bcf a day actually was shipped on tankers.
Of the 83 terminals, 49 of them - with a capacity of 28 bcf a day - started in the last five years.
Remember the rosy forecasts of U.S. LNG imports? North American companies dropped billions of dollars building or expanding LNG terminals, betting the forecasts would come true. As a result of this build-out, the United States can import up to 17 bcf a day of LNG. Reminder: actual imports averaged 1.2 bcf a day last year, a figure that's falling.
The biggest LNG customers worldwide are utilities in Japan and South Korea. Those two nations bought nearly half of the LNG made last year. Europe also is a major destination, with Spain, Great Britain and France together taking 20 percent of the world's LNG. European nations have been buying more LNG to try to diversify their supplies away from piped Russian gas.
Sweden and the Netherlands should join the cast of LNG importers this year.
South America is a new and growing destination for LNG. Argentina got its first load in 2008. Brazil and Chile got their firsts the next year.
Argentina once exported its excess gas production. Now it needs to import LNG.
Ironically, Chile built its LNG terminal after Argentina - struggling to meet local demand - cut off exports from a pipeline that crosses the Andes. Chile now might send regasified LNG via the same pipeline to Argentina.
Bill White is a researcher/writer for the Office of the Federal Coordinator for Alaska Natural Gas Transportation Projects, an office established by the U.S. Congress in 2004 "to expedite and coordinate federal permitting and construction of a pipeline to deliver natural gas from the Arctic to North American markets, and to enhance transparency and predictability of the federal regulatory system for the project." This article first appeared on the Federal Coordinator's website.
The views expressed here are the writer's own and are not necessarily endorsed by Alaska Dispatch. Alaska Dispatch welcomes a broad range of viewpoints. To submit a piece for consideration, e-mail commentary(at)alaskadispatch.com.