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Analysis: More U.S. utilities switch from coal to natgas
February 10, 2011 / 12:07 PM / 7 years ago

Analysis: More U.S. utilities switch from coal to natgas

NEW YORK (Reuters) - A narrowing gap between coal prices and cleaner natural gas is accomplishing in the short-term what U.S. regulators hope to achieve in the long-term -- forcing more power plants to burn gas instead of coal.

<p>A liquefied natural gas terminal in a file photo. REUTERS/Stefano Rellandini</p>

Coal prices hit a 26-month high last month as natural gas struggled to break $5 per million British thermal units, putting the two fuels at cost parity for U.S. Southeast power plants -- an unprecedented incentive to burn gas in the middle of the winter, when frigid weather normally makes coal the clear choice.

That may be only the start of a record year for power companies to make the switch in order to boost profits.

Unlike 2009, the last year in which widespread fuel switching became a factor for markets, the change could be more sustained in 2011 as utilities anticipate a looming carbon crack-down by the Environmental Protection Agency.

Coal prices may remain elevated for some time as Asian demand grows while Australian mines struggle to make up for lost volume following massive flooding.

Meanwhile, natural gas prices, though off last year’s lows after some of the coldest temperatures in 60 years this winter, threaten to remain depressed for years.

Extraction of massive U.S. shale gas reserves promise decades of abundant supply, boosting industry confidence that low natural gas prices are not a fleeting aberration.

“We believe coal-to-gas switching will be taking advantage of that price level driven by the increasing domestic production and overall U.S. supply in 2011,” says Brannin McBee, an energy analyst with Bentek Energy, an arm of Platts.

He expects to see 2.5 bcfd of coal to gas switching this year given a $3.75 gas price, -- equivalent to displacing roughly 13,000 MW or about 4 percent of total coal capacity.

Michael Zenker, managing director in commodities research in San Francisco with Barclays Capital, believes utilities will burn some 3.7 billion cubic feet per day this year to generate power in place of coal, exceeding the estimated 2.75 bcfd registered in 2009.

Even that extra demand pull may be insufficient to avoid a further collapse in prices at the end of the summer, when U.S. storage tanks may fill to capacity unless production is shut.

“Even with that level we still think we’ll reach record (natural gas) storage levels,” he said.

On a 30-day average basis, the cost of burning gas dropped to its lowest relate to coal in November, and has failed to return to its traditional premium since then, according to Bentek data based on U.S. Southeast power plants, those most able to switch from coal to gas. (Graphic: )

The U.S. Energy Information Administration estimates that natural gas accounted for roughly 24 percent of U.S. power generation last year, up from nearly 19 percent in 2005.

In 1990, natural gas accounted for just 12.3 percent of generation.


Some utilities have already begun shifting generation. The Tennessee Valley Authority, which supplies power to U.S. states in the Southeast and burns coal to generate two-thirds of its electricity, has increased its non-coal share to 4 percent from around 1 percent in 2006.

“...low natural gas prices during 2010 have made these units more economical to operate,” the U.S. government-owned corporation said in a regulatory filing last year.

“It is TVA’s intention to significantly increase production from low-emission generation facilities with the addition of natural gas plants to its generation fleet in the near future,” it added in the report.

Switching to gas from coal got a boost late last year when gas prices hit a 13-month low in October at $3.21, but they have quickly rebounded. Analysts estimated between 1.1-to-2.5 bcfd of gas displaced coal in 2010, when Henry Hub prices averaged $4.381/mmBtu -- up from $3.99 in 2009.

This year, prices are forecast to average $4.43 [ID:nN2810395] and storage levels are expected to finish out the winter heating season at 1.643 trillion cubic feet, 5 percent above the five-year average [ID:nN27188391].

“We are looking at gas as a more viable option in the short term,” David Owens, executive v.p. with the Washington, D.C.-based utility trade group Edison Electric Institute told Reuters. “We see growing dependence on the fuel assuming natural gas prices are low and assuming there are no (environmental) issues with shale gas.”


It can be difficult to determine when the economics work for plants, especially as the benchmark coal price any one power generator uses to make a decision to switch could be based on a price very different than the spot market.

“The headache for the gas market is that it isn’t as uniform in how they value the fuel as it is for gas,” Zenker said.

Zenker estimates that the switch occurs in incremental volumes at a natural gas price of around $5.50 and the closer prices approach $3.50 per mmBtu the closer the market gets to a full 3.7 bcfd of coal displacement.

The rough natural gas price equivalent for a $75.50 ton of Central Appalachian coal is about $3.15 a million British thermal units. That figure does not take into account variable costs such as power plant efficiency, transportation costs or any fees associated with permits to burn coal.

Zenker estimates some 60,000 MWs -- just under 20 percent of total U.S. coal generating capacity for winter power generation, according to U.S. data -- are in the running for coal displacement in the eastern U.S. at any given time.


Underlying the longer-term shift is growing evidence that the United States is sitting on decades’ worth of untapped natural gas trapped in shale rock formations, enough to keep a lid on prices for years to come.

In December the Energy Information Administration doubled its estimate of unproven shale gas reserves to 827 trillion cubic feet, from a 474 tcf estimate the year before.

At the same time, storage capacity has grown, but not fast enough to accommodate the rush of new production. Last April the IEA revised upward its estimate of working gas storage to 4.049 trillion cubic feet, up by 160 bcf from a year earlier.

In July, it reported that U.S.-marketed production of natural gas in 2009 reached 21.9 tcf, “the highest recorded annual total since 1973.”

The amount of natural gas in storage fell below the five-year average on Thursday for the first time in a year.

Still, futures prices settled below $4 to their lowest level in nearly two months.

Even considering lower Canadian imports and minimal imports of liquefied natural gas, the U.S. will be awash in natural gas by the beginning of the next winter heating season, McBee said.

“We’re expecting that gas prices remain suppressed due to physical storage limitations,” he said. “The market will already be flooded and we’ll still be running out of room to put it in the ground.”

Reporting by Jeanine Prezioso; Editing by David Gregorio

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