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MEET ALASKA 2005: Window of opportunity yawns wider Key is to get North Slope gas to market before nuclear and coal fill the gap; winning strategy for Alaska gas line remains elusive Rose Ragsdale Petroleum News Contributing Writer
Natural gas consultant Pedro van Meurs told an Alaska legislative committee last fall that all of Alaska’s competitors are doing quite well, but Alaska is not yet out of the starting gate.
Opportunities to market natural gas are plentiful, both at home and abroad. Here in North America, the prospects for selling Alaska North Slope gas have never been brighter.
“Changes in North American gas marketing in recent years bode well for Alaska gas,” said Dave MacDowell, a spokesman for BP Exploration (Alaska) Inc.’s gas group. “North America is the largest and deepest natural gas market in the world.”
But gas demand is growing and traditional natural gas sources are increasingly unable to keep pace, according to MacDowell.
Roger Marks, an energy economist with the Alaska Department of Revenue, agrees. “Demand for gas in the Lower 48 is a lot stronger than supply, and there’s no reason to think it will change in the future.” Gas prices, demand and production up Tight supplies have kept prices high, resulting in rising natural gas and electric bills, sharp increases in the price of the chemicals used to make plastics and raising questions about the long-term future of U.S. chemical makers.
The U.S. Department of Energy’s Energy Information Administration reported Jan. 11 in its Short-Term Outlook that the average Henry Hub natural gas spot price was $6.32 per thousand cubic feet in November and $6.77 per mcf in December. However, recent unusually mild winter weather in the Northeast reduced heating demand, which in turn, lowered spot prices for natural gas. Between Dec. 20 and Jan. 3, the price at the Henry Hub fell sharply from $7.35 per mcf to $5.70 per mcf.
Working gas in storage is estimated to have totaled 2,698 billion cubic feet at the end of December, up 5 percent from a year ago and 12 percent higher than the five-year average, according to the EIA. With the heating season now more than half over and ample gas in storage, natural gas prices are likely to ease over the next several months. Henry Hub prices are expected to average $5.77 per mcf in 2005. In 2006, prices are projected to average $5.95 per mcf as the supply of natural gas is expected to tighten.
In response to continued economic growth in the United States, the EIA projects natural gas demand to increase by 3 percent in 2005. However, domestic natural gas production in 2005 is projected to increase by 1.7 percent from 2004 levels, partly due to high gas-directed drilling rates and partly due to continued recovery in the Gulf of Mexico from the effects of Hurricane Ivan. Steady increases in liquefied natural gas imports, restrained export growth, and carryover from the robust storage levels noted above are expected to contribute to a moderate improvement in the supply picture in 2005.
In September, the EIA said U.S. proved reserves of natural gas increased for the third year in a row in 2003. The agency’s “Advance Summary: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report,” showed U.S. natural gas reserves up 1 percent in 2003.
The increase in natural gas reserves, the majority from extensions of existing conventional and unconventional gas fields, was the fifth time in five years gas reserves have increased, with 111 percent of gas production replaced. Gas production remained almost level in 2003 as declines in the Gulf of Mexico and New Mexico were offset by production increases in the Rocky Mountain states and Texas.
In its first step to drafting new energy legislation, the Republican-controlled U.S. Senate Energy Committee made plans earlier in January to hold a special conference Jan. 24 to consider proposals to boost gas supplies.
Congressional lawmakers say they want new ideas to help increase domestic drilling, ease regulatory burdens and bolster gas imports through construction of new liquefied natural gas terminals.
They point to forecasts like those from the EIA, which suggest gas demand will rise from 22 trillion cubic feet in 2003 to nearly 31 tcf by 2025.
MacDowell and Marks say nontraditional sources of gas, including liquefied natural gas imports and gas from Canada’s Mackenzie Delta and Alaska’s North Slope will be needed to fill the widening gap between gas supply and demand.
“A lot more will be required just to run in place,” MacDowell said.
The growing gap also has fostered a new era of high gas prices. In the past five years U.S. gas prices at the wellhead have jumped from a low of $2.19 per mcf to high of $6.82 per mcf. Natural gas imports also followed the trend, dipping to $2.32 per mcf and peaking at $9.47 per mcf.
In 2004, gas prices leveled off in the $5 per mcf to $6 per mcf range, substantially higher than the average $2 per mcf to $3 per xmcf range of the late 1990s. Market looks for alternate energy sources Marks said the way the gas market is responding to the new higher price era is power plants are being built using alternative sources of energy. This includes dual-fired plants that use gas and other energy sources. “Nuclear could make a comeback or clean coal could be a source,” he said.
In addition, a few LNG terminals are being built and existing ones are eyeing expansion.
One LNG terminal could even present an opportunity for Alaska. Sempra LNG, a unit of Sempra Energy, recently entered a development agreement with the Alaska Natural Gas Port Authority in which it will consider expanding Energia Costa Azul, a planned 1 bcf per day LNG terminal in Baja California, to accommodate shipments of Alaska gas from the Port of Valdez.
In a statement, Sempra Energy President and CEO Donald Felsinger said, “it is important that the vast natural gas resources of Alaska be delivered to the U.S. markets as quickly and efficiently as possible, and we think this project has the best potential of doing that.”
Sempra’s LNG terminal is expected to be the first LNG receiving terminal on the West Coast when it comes online in 2008, he said.
The port authority estimates that its Alaska LNG project, which would transport anywhere from 3 bcf per day to 4.5 bcf per day, could be ready to deliver LNG to the West Coast as early as 2011. Of the initial volume, port authority officials estimate not less than 2.5 bcf per day of gas would go to Sempra.
Port authority members include the City of Valdez, the Fairbanks North Star Borough and the North Slope Borough.
But Marks at Revenue said Sempra is committed to suppliers in Australia and Indonesia, including its joint venture partner Shell, for its initial 1 bcf per day of gas imports, and most analysts believe the West Coast market can only absorb another 1 bcf per day in gas over the next decade.
The problem is an Alaska LNG project needs to sell 4 bcf per day to be economic, he said, and other Pacific Rim markets are able to buy LNG from new projects in Qatar and Indonesia for lower prices in the $3-$4 per mcf range. Window of opportunity for Alaska is multifaceted Higher gas prices in the Lower 48 present a “real window of opportunity for Alaska,” said Larry Houle, general manager of the Alaska Support Industry Alliance.
Houle said the opportunity is one of economics because higher prices will make the proposed $20 billion Alaska gas pipeline more affordable and also one of marketability because utility regulators in the Lower 48 are more likely to welcome a reliable source of a large amount of gas.
While most regulators in the Lower 48 aren’t allowing their utilities to enter long-term contracts, Houle believes that could change.
“With a constant, reliable 30- to 40-year supply of gas from Alaska, I think the regulators will be more receptive to long-term contracts, which would significantly lower the risks of building the gas line,” he said.
“I’ve never been enamored of the ‘window’ concept, but I think the market will be there and continue to grow,” Marks said.
University of Alaska Fairbanks economics professor Doug Reynolds also believes the time is right for construction of a natural gas pipeline from Alaska’s North Slope to existing pipe infrastructure in Alberta, feeding into the Midwest and eastern portions of the United States.
In an analysis completed last year, Reynolds observed that supplies from the Atlantic basin — Norway, Russia and Trinidad and Tobago — are tightening up, and prices for gas are increasing. Demand for natural gas in the Midwest and in the eastern United States is also increasing quickly, at a rate of 2 percent a year, he told a Fairbanks audience. “This is going to happen. It would be a shame if it doesn’t,” he said. “The economics are there … there’s the potential of prices being high for quite a few years, even with LNG competition in the Pacific Rim.”
He compared recent spikes in natural gas prices and the current 66-year supply of gas reserves in the Atlantic basin with the 1970s oil crisis in the United States.
Back then, crude producers reported a 37-year reserve in oil resources, Reynolds said. A reduction in production and an increase in prices helped create a crisis that resulted, in part, in the construction of the trans-Alaska oil pipeline.
“It’s harder to develop natural gas and get it to market, so (the 66-year Atlantic basin reserve) is on par with the 37-year (oil) reserve,” he said.
The state’s royalty benefits would be greater with a gas pipeline project selling to users in the Lower 48, compared to a liquefied natural gas project selling to Pacific Rim buyers, Reynolds said, because wellhead values for gas piped to the Lower 48 would be about $2 per mcf, compared to about $1.30 per mcf for a LNG project selling to the Pacific Rim. Opportunities must outweigh risks With so many promising opportunities to develop and market Alaska gas, why is the pipeline project still a concept more than reality?
It’s the unique risks associated with commercializing Alaska North Slope gas, says consultant van Meurs.
The project is huge: Compared to the current 40 largest oil and gas projects in the world, the Alaska natural gas pipeline project, at $18 billion, is three times the size of the next largest. According to van Meurs’ data, even at $14 billion (connecting to Canadian infrastructure) the Alaska project is more than twice the size of the next largest, with a capital expenditure of some $6 billion.
The “gigantic size” of the project, van Meurs said, is a risk by itself: if you failed with this project the risk for your company is “horrible.” Size creates another risk: the huge upfront capital requirements mean the project has a low rate of return compared to competing projects, and that’s related to the project size, he said, not to Alaska’s fiscal system.
Cost overruns are another real danger. Then there’s the regulatory environment, he said. North America has the most complex regulatory environment in the world. Competitors, he said, don’t have regulatory risk.
Moreover, no one can predict future gas prices, said BP’s MacDowell. “But we can reduce the other risks associated with the gas pipeline project,” he said.
BP and the other North Slope gas producers, ExxonMobil and ConocoPhillips, have spent more than $125 million studying the project and concluded that it will need four important elements to succeed.
North Slope producers seek four-part foundation for gas pipeline project
Describing the elements as the four legs of a stool on which the project would rest, MacDowell said Congress supplied one leg with its enabling legislation last fall, and the other three legs must come from Alaska, Canada and cost reductions.
The producers, who are currently in negotiations with the state of Alaska, say they would like to see the state Legislature approve an enduring, equitable fiscal contract this spring.
The upside potential for the project, with fiscal stability, is also very high, van Meurs said.
The passage of the federal gas pipeline legislation Oct. 11 was “a gigantic step forward,” but the onus is now on Alaska: “Now we are the only ones standing in the way of this project,” van Meurs added.
Marks agreed that the ball is in Alaska’s court. “It’s a wonderful opportunity for Alaska. But it’s a very complicated one,” he said. No slam dunk Marks said developing a $20 billion gas pipeline will be exceedingly complex, especially if it is built all the way to Chicago. “The builders will have to deal with a lot of government jurisdictions,” he said.
But with a durable fiscal contract from the state of Alaska in hand, MacDowell said the producers could move forward with the next phase of the gas line project, the $1 billion permitting and engineering phase.
This work would enable the producers to then seek an efficient regulatory process in Canada from that country’s National Energy Board. The process would include securing permits and rights of way from provincial and First Nation governments, MacDowell said.
In obtaining the fourth element of the project’s foundation — cost reductions — the producers also have made considerable progress. This effort is ongoing, but cost cuts, so far, equal 10-15 percent of projected total spending for the gas line, MacDowell said. Savings have been identified in materials, such as high-strength steel, and techniques such as automated welding and trenching, he said.
“We feel pretty good about our cost reduction efforts to date, but lots of things could affect that,” MacDowell said.
Once all the government regulatory frameworks are in place, the gas producers will need two to three years to do the permitting and engineering work, up to two years for the Federal Energy Regulatory Commission to review the project, two years for pre-construction logistics and three years to actually build the pipeline.
That’s a total of nine to 10 years from the point when the $1 billion phase commences, MacDowell added.
Alaska officials recognize that whoever takes up the challenge of building the pipeline will need fiscal certainty and certain key fixes to the fiscal code, Marks said.
Though the state is in concurrent negotiations with the producers and pipeline company TransCanada, Marks said Alaskans should not expect to see quick action.
“We may have to be patient to have the pipeline evolve,” he said. “The bottom line is it’s just huge. It’s doable, but you have to move carefully.”
“To get this project going requires unique solutions,” van Meurs added. “It won’t go by itself.”
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