Gas-fired plants regain the advantage
For the past five years or so, the big story in U.S. power generation has been the retreat from natural gas, which was the fuel of choice in the 1980s and 1990s. Gas, long in surplus (remember the “gas bubble?”) and featuring steady and declining prices, was the ideal generating fuel for the end of the 20th century. Generators could build low-capital-cost units and arbitrage the different market prices for gas and electricity—the “spark spread”—at will. So build they did, because the economics continued to favor gas.
With low plant upfront costs and short construction times, natural gas dominated. Though gas is costlier than coal on a $/Btu basis, the low heat rates of combined-cycle combustion turbine plants minimize the premium as they operate. The emissions profile of gas plants looked good, particularly compared to coal. Through the ’90s, environmentalists gave gas a pass, seeing it as the transition fuel to a renewables future.
That changed around the end of 2001 (about the same time as the fall of the House of Enron). Gas inventories plummeted, in part due to the collective demand of all those new combined-cycle plants. Prices became volatile. Generators that had dashed to gas now fled from it. Scores of gas-fired projects announced late in the gas boom never made it off the drawing board.
Today, gas has regained some of its glitter. As crude oil prices surged above $90/bbl, the alleged linkage between the prices of oil and gas proved to be a myth. Gas prices have stabilized. They appear to have leveled off at around $7 per thousand cubic feet—well below the prices seen earlier this decade.
As a result, gencos are again considering natural gas plants their least-risky option, in light of gas plants’ low capital and construction costs and the political incorrectness of the nuclear and coal alternatives. Randy Zwirn, CEO of Siemens Power Generation, told an industry meeting last year, “By default, the only technology that’s going to be available is gas-fired generation.”
Although attention recently has focused on new nukes and cancelled coal, gas has been showing stealth strength. A recent EIA report noted that natural gas–fired generation “showed the highest rate of growth from 2005 to 2006 of the traditional energy sources,” accounting for 20% of all new generation in 2006. Compared to 2005 figures, said the EIA, gas-fired generation in 2006 grew by 7.3%, while nuclear grew by 0.7% (due to upratings and better plant performance) and coal fell by 1.1%.
Increasing gas reserves fuel optimism
Is enough gas available to supply new power plants as well as residential and industrial furnaces? Last October, the DOE’s Potential Gas Committee, a group of volunteer energy experts, issued a new estimate of recoverable domestic gas reserves that is 17% higher than one made in 2004. The committee said the U.S. has some 1,525 trillion cubic feet of recoverable gas, compared to its 2004 estimate of 1,308 tcf.
That’s the largest increase since the committee started estimating reserves in 1964, according to The Energy Daily (like POWER, an Access Intelligence publication). The committee said new reserve estimates exceed the 36 tcf of gas that U.S. producers extracted between 2004 and 2006.
Meanwhile, the 2007–2008 winter assessment by the Federal Energy Regulatory Commission (FERC) found, “For the second year, the prospects for natural gas markets as we head into this winter are very good.” FERC staffers said gas storage is “robust,” winter temperatures are forecast to be mild, new pipelines and liquefied natural gas (LNG) terminals are coming on-line, and gas in storage should exceed record levels as winter kicks in.
The FERC staff report concluded, “Basically, we expect to see full storage this year. Effectively full storage goes a long way toward protecting the country from the disruptions and price spikes associated with tight supply/demand balances in the winter.” If the forecasts for a warmer-than-normal winter are accurate, said the report, “gas prices could remain stable or even see some downward pressure.”
Last November, the EIA reported that proved U.S. natural gas reserves grew by 3% in 2006 to 211 tcf. That’s the highest reserve level since 1976, the agency added. The driver of that growth was the use of new drilling techniques that have given explorers access to unconventional gas, such as the Barnett Shale in Texas. According to the EIA, additions to gas reserves in 2006 replaced 136% of the gas produced that year. It was the eighth straight year that proved gas reserves have grown.
Concrete evidence that utilities are not shying away from natural gas comes from Duke Energy, which last summer asked the NCUC to approve up to 1,600 MW of new combined-cycle gas-fired capacity after having its proposal to build the same amount of coal-fired capacity turned down. Florida utilities are also looking seriously at new gas units, likewise following rejection of coal-fired plants.
A most unusual gas-fired plant has been proposed by Basin Electric Power Cooperative, a large generation and transmission co-op based in Bismarck, N.D. In late October 2007, Basin said it would like to build and commission a 300-MW unit in the eastern part of the state by 2012. At the heart of Deer Creek Station would be a simple-cycle combustion turbine generator and a heat-recovery steam turbine generator. Both would run about 12 to 16 hours a day in intermediate service, following load on the systems of the distribution cooperatives that Basin supplies.
What’s unusual about that? Nothing. However, Deer Creek would burn synthetic gas (syngas), rather than natural gas. The supply would come from Basin’s Dakota gasification project, which uses Lurgi technology to turn lignite into syngas that then can be transported by the Northern Border Pipeline. Developed in the 1980s, the Dakota project is America’s only large-scale converter of coal to gas. The fact that it has never been replicated in the U.S. suggests that there are cheaper ways to go.
LNG lags behind
Early last year, there was buzz about liquefied natural gas. By the beginning of 2008, it had quieted to a murmur. Ambitious LNG projects became stalled as a result of intense local opposition and stabilization of the conventional U.S. natural gas market.
According to FERC, five LNG receiving terminals with a total capacity of about 6 billion cubic feet (bcf) per day operate in the U.S. today. The agency has approved another 21 projects but acknowledges that most of them will never be built.
For example, California Gov. Arnold Schwarzenegger in May last year rejected a plan for an $800 million LNG terminal off the Southern California coast proposed by an Anglo-Australian company. Earlier, the California Coastal Commission had unanimously rejected the project.
Nor does there appear to be a crying need for LNG in today’s market. A Reuters story last October noted that LNG imports to the U.S. were expected to continue a slide begun several months earlier, “as steady demand from the Far East and early buying from Europe soak up more spot supplies.”
According to the Houston-based consultancy Waterborne Energy, U.S. LNG imports in September 2007 were about 45 bcf, or about half the 89 bcf imported in August 2007. The firm’s estimate for October was less than 45 bcf. Weather was partially responsible, said Waterborne. While unseasonably cool weather in the UK raised natural gas prices to about $9/mmBtu, a mild autumn in the U.S. Northeast saw gas prices drop to about $6/mmBtu at the Henry Hub market. The LNG flowed to the UK.
In their forecast of natural gas markets for 2007 and 2008, FERC staff portrayed LNG as a swing resource. According to FERC’s director of gas market oversight, Steve Harvey, LNG acts as insurance. “Depending on international gas prices,” he said, “supply may or may not be available to U.S. markets.” So much for the LNG boom.
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