Bernstein expects more coal-to-gas switching in Q2

Analysts for Bernstein Research expect to see even more coal-to-natural gas switching in the power generation industry during the second quarter of 2012.

Senior Bernstein analyst Hugh Wynne and others laid out their thoughts on the issue during an April 20 conference in New York, according to a transcript of the event.

“The 30% year-over-year surge in gas use by the power sector in Q1 2012 is likely to continue, and probably accelerate, in Q2,” the Bernstein analysts conclude. Second quarter power sector demand for natural gas could increase anywhere from 9% to 12%, if current trends persist.

The analysts suggest natural gas generation would have been even higher during the first quarter if the winter had not been so mild in much of the country.

Under a base case average of around 625 gas rigs and 4-5 Bcfd of switching from April through November, Bernstein’s forecast expects peak inventories to fall below the maximum demonstrated storage capacity, “implying that we could have gas prices above $3.00 in November.”

If, however, coal-to-gas switching falls below first quarter levels and averages “less than 4 Bcf/day through November, and the average rig count exceeds 625, there is a substantial risk that the inventory build will exceed storage capacity, sending gas prices to down to the variable cost of production, or approximately $1.50/mcf,” the firm suggests.

“Natural gas prices, in our view, aren’t likely to move substantially to the upside until the industry is comfortable enough with November’s storage outlook, which depends on a) E&Ps’ discipline to cut dry gas activity, b) associated gas volumes coming online in liquids plays, and c) a few months’ run-rate of coal-to-gas switching,” according to the Bernstein analysis.

Gas prices have fallen from an average of $4.20/mmBtu in the first quarter of 2011 to an average of $2.50/mmBtu in the first quarter of 2012, Wynne said.

By way of example, American Electric Power (NYSE: AEP), has disclosed that its eastern coal fleet, which burns largely Appalachian coal, ran at a 47% capacity factor in the first quarter of the year, while its combined-cycle gas turbines were dispatched at an 85% rate once the newly-opened Dresden gas plant was included. “This is precisely the reverse of the historical capacity factors for plants burning these two fuels over the last decade,” Wynne said.

U.S. Energy Information Administration data shows that coal-fired generation fell much more than total power demand in recent months, “suggesting that coal has replaced gas as the marginal fuel,” Wynne said.

Despite long-term contracts, the electric utility industry has a surprising degree of leeway to reduce its coal consumption. That’s because a lot of power plant coal is being bought either on the spot market or through contracts that expire at the end of 2012.

“When you purchase 7% of your coal supply spot and 29% of your coal supply under contracts expiring in the current year, you obviously have significant flexibility to reduce your consumption of coal,” Wynne said.

Also, utility coal stockpiles, while larger than in recent times, are still below capacity, Wynne said.

About Wayne Barber 4201 Articles
Wayne Barber, Chief Analyst for the GenerationHub, has been covering power generation, energy and natural resources issues at national publications for more than 20 years. Prior to joining PennWell he was editor of Generation Markets Week at SNL Financial for nine years. He has also worked as a business journalist at both McGraw-Hill and Financial Times Energy. Wayne also worked as a newspaper reporter for several years. During his career has visited nuclear reactors and coal mines as well as coal and natural gas power plants. Wayne can be reached at wayneb@pennwell.com.