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Cambridge Energy Research pessimistic about Alaska gas CERA updates state on prospects for Alaska North Slope gas, says Lower 48 gas prices have pushed pipeline out to 2015, Alaska LNG too costly in an over-supplied Pacific market and Alaska costs make gas-to-liquids uncompetitive Kristen Nelson PNA Editor-in-Chief
There was no good news when Cambridge Energy Research Associates updated the state on prospects for Alaska natural gas Dec. 19. When the Alaska Department of Revenue contracted with CERA for 2001, said Ed Kelly, in Anchorage from CERA's Houston office, it asked for a global perspective on the market and on how Alaska gas would fit into that market.
The December update was focused on global liquefied natural gas and gas-to-liquids, but in response to a question about the prospects for a natural gas pipeline from Alaska to the Lower 48, Kelly said CERA now believes the window for Alaska gas to the Lower 48 has moved out some five years — to about 2015 — because of sluggish economic growth (see Dec. 23 issue of PNA).
Michael Stoppard, by phone from CERA'a Paris office, said CERA sees the Pacific basin as pretty well supplied with liquefied natural gas for the next 10 years, and does not see an Alaska LNG project — which would require an expensive pipeline to get the gas to a liquefaction plant — as part of that supply.
And Martin Meyers, in a phone presentation from Boston cut short by a power failure in Anchorage, said CERA expects to see a pretty substantial gas-to-liquids business emerge over the next 20 years, but it will be a competitive commodity business and CERA doesn't see Alaska as being among the low-cost places to develop GTLs.
Changes in LNG over 12 months Stoppard, who coordinates CERA's global LNG studies, said there have been some major changes in LNG in the last 12 months.
The demand story for LNG is very bright, he said.
“But the word of caution is that the supply side of the story looks increasingly competitive and tough. And that therefore we can expect to see some changes in the traditional way that the business is done and possibly in the way that LNG prices are set and indexed.”
Worldwide, he said, gas associated with oil was often flared, but there is “strong government pressure around the world to reduce gas flaring” and “more importantly, the major international oil companies are very sensitive about gas flaring.”
Coupled with the desire to monetize gas, there is what Stoppard called “a very significant improvement in cost recently in the liquefaction process.” This is not a technological change, but is due to competition in building liquefaction facilities. There are two processes available, and new facilities are now asking for bids for both processes.
Economies of scale are also reducing costs as liquefaction plants get larger. A couple of years ago, Stoppard said, 3 million tons was a normal LNG train — but most new projects are going to be 4.5 to 5 million tons.
LNG shipping fleet set to grow dramatically One of the biggest LNG stories, Stoppard said, is in shipping. “There are 128 ships in the LNG fleet,” he said. “By 2004, it's highly likely that there will be over 160. That's a massive increase in the LNG shipping fleet.” It took 30 years to get to 128, he said, and over the next three years the count will rise to more than 160, most probably more than 170. And those new ships will be large.
“But the basic message is that we are probably moving from a world of constraint on shipping in LNG to a world in 2003 to 2006 when we will have a surplus of LNG shipping, which would be our baseline expectation,” Stoppard said.
The cost of LNG ships has also come down. They cost as much as $320 million in the past, he said, and the cost has been coming down through the 1990s “from just over $200 million a ship to as low as $150 million a ship.” Shipyard constraints are now edging costs back up as LNG tankers compete for slots with double-hulled very large crude carriers.
But the main cost difference in shipping LNG remains the distance, Kelly said:
“The number of days the ship must be on the ocean to get from a supply point to a particular market point is the lion's share of the difference in the shipping cost from one supply terminal to a market terminal.”
Re-gasification proposals There are also dramatic developments in re-gasification, Stoppard said, with proposals to site receiving terminals into the United States on the both the East and West Coasts. Twelve months ago, he said, it was not evident there would be any additional LNG shipping terminals in the United States beyond the four which are operating or being re-opened. Most of the proposals will never get built, but the cost of re-gasification is now less than $200 million a plant, putting it within the reach of a wide variety of companies.
Kelly said CERA believes maybe one or two new re-gasification facilities could be built, “one on the West Coast of Mexico — which would actually feed into the U.S…. but could feed into the Mexican grid as well, and one on the East Coast of Mexico feeding into the Mexican grid.”
Rigid contracts being undermined CERA is also seeing changes in how LNG is sold. Stoppard said “almost all the LNG trade that is going on today is in fairly rigid bilateral contracts... Anything that's going into Japan or into Europe, you've got a rigid bilateral contract.”
But when U.S. prices were very high in early 2001, European cargoes under long-term bilateral contract were diverted to the United States.
“So clearly it is possible to come to a mutually beneficial commercial agreement that takes precedence over what's written in the contract,” Stoppard said.
Contracting is also changing. Taiwan recently used “a competitive tender for supply. “
“Which is a radical departure from the typical system of developing a long-term bilateral business relationship with companies and with individuals… over many years,” Stoppard said.
“They're basically taking bids” in Taiwan, said Kelly.
There “is a lot of talk and discussion about whether LNG will become a normal commodity business by which basically means will people build a liquefaction plant without take or pay contracts? Or without long-term contracts. And just hope to sell the LNG as a commodity,” Stoppard said.
CERA thinks that unlikely, he said, because the $1 billion cost of an LNG plant.
But the expectation is that facilities will go ahead without 100 percent of output contracted. A 5 million ton train, for instance, might be built with 4.5 million tons contracted, Stoppard said, “and then you've got a little bit on the margin to play with the trading market.”
Asia will continue to be focus of LNG trade The global LNG market, about 100 million tons today, could double by 2010 with economic growth, but will move from 100 million to 150 million tons even under CERA's more conservative scenario, Stoppard said.
Oil companies, he said, are under very strong pressure from the financial community to show growth and are looking for organic growth.
“And there isn't much organic growth in the oil business. If you're looking at 1-2 percent oil demand growth it's difficult,” he said. LNG presents a way to grow organically, at rates of 5-10 percent and LNG is environmentally sound, an “essentially attractive growth” opportunity, Stoppard said.
LNG remains an Asian business, with 71 percent of LNG in Asia, 24 percent in Europe and 5 percent in America in 2000.
More than 50 percent of LNG in 2020 will still be in the Asian market but the Americas will grow to 18-19 percent. Still small volumes compared to the overall natural gas market in America, Stoppard said, but enough to make it a significant potential demand target.
Supply exceeds demand CERA has put together a worldwide supply-demand balance. “And not surprisingly, we found out that expected LNG supply was in excess of LNG demand,” Stoppard said. Over the past 12 months, the demand side for LNG has moderated, but “on the supply side we're seen more and more projects being touted and being put forward… and so we have quite a bullish view on supply, slightly bearish on demand.”
The “inability to involve all the potential supply” has put “downward pressure on price,” he said.
In the Atlantic basin demand is expected to be 80 million tons — Europe and America together — which will be supplied out of the Atlantic basin or Mediterranean, Stoppard said.
Demand in the Pacific by 2010 will be “somewhere between 100 and 130 million tons. About three-quarters of that can easily be met in the Pacific basin, Stoppard said. The Middle East probably won't capture more than about 35 million tons by 2010.
Conservati “Under our conservative scenario,” Stoppard said, “the whole of the world's LNG requirements for 2010 are already under construction with very little room for new contracts.
“Under our more positive… scenarios, there's space for another approximately 50 or 60 million tons to be developed.”
And there are known competitors for that 50 to 60 million tons, Kelly said.
By 2006, the Pacific basin will have something like 70 million tons of liquefaction capacity.” Asian demand by 2010 will be between 100 and 120 million tons. Liquefaction in the Pacific basin by about 2004, will be about 70 million tons and with approximately another 30-32 million tons in the Middle East. So that gets you up to about 100. So you're up to about, you're probably up to about 100 million tons by about 2004. And then there's a 20 million ton upside going out over the next five, six, seven years.”
“It's not the message I would like to be delivering to this audience, but I think it needs to be said loud and clear. I think pretty much the conventional wisdom …the Pacific basin is seen as pretty well supplied for the next 10 years,” Stoppard said.
Alaska GTL not economic Meyers, who follows the refinery products business for CERA, only got in a brief introduction before he was cut off by a power outage in Anchorage, but did say there will be a pretty substantial global gas-to-liquids business emerging over the next 20 years, with as much as 2 million barrels a day of GTL productive capacity.
The technology message is encouraging, he said.
“But the other part of the message that I put to you is that in our view Alaska is probably not among the most likely sites for a gas-to-liquids development given cost.”
The problem, he said, is that GTL “plays in this energy game which is a pretty brutal competitive commodity business and those with low costs are those that survive and prosper.”
For this particular technology, Meyers said, “we don't see Alaska as being among the low-cost places to develop this technology.”
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