The key word for the Duke Energy (NYSE:DUK) coal plants in the future, in terms of things like coal sources and the ability to ramp the plants up and down, is “flexibility,” said B. Keith Trent, Duke’s Executive Vice President and COO–Regulated Utilities.
In a keynote speech Aug. 14 at PennWell’s Coal-Gen 2013 conference in Charlotte, N.C., Trent said that in the face of clean energy initiatives and cheap natural gas, coal plants face “big headwinds” and must be flexible to survive and run.
He noted the effort by Duke to test new coals, a mix of Powder River Basin and western bituminous coal, at Crystal River Units 1-2 in Florida, which are units that normally burn Central Appalachia coal. The coal changes are designed to meet the Mercury and Air Toxics Standards (MATS) without expensive new emissions control technology.
Another example is the Belews Creek plant in North Carolina, where a goal last year had been to test blends that included up to 20% cheaper Illinois Basin coal in place of part of the regular Central Appalachia coal burn, but that blend actually got up to 35% Illinois Basin coal instead.
At the Allen plant, there was an innovative effort to blend flue gas, basically firing one type of cheaper, higher-sulfur Illinois Basin coal in one boiler, more costly Central Appalachia coal in another boiler, then achieving needed SO2 limits as those emissions were averaged in a common stack.
Trent noted that many coal plants aren’t operating at baseload these days. For example, Allen only operated at a 5%-10% capacity factor last year. That has left Duke looking for ways to keep staffing the coal plants at levels that make sense while keeping staff levels down, in part by shifting around employees, as needed. One flexibility being pursued by Duke is a shift of its traditional focus on getting the best possible heat rates from the coal plants, to prioritizing flexible operations.
He noted how the new Cliffside 6 coal unit was brought into full operation at the end of 2012, with four older coal units at the site retired to more than offset the emissions from Unit 6. Cliffside Unit 5 has survived the shutdowns, but is lightly used. Another new facility for Duke is the Edwardsport coal gasification power plant in Indiana. There are also new gas-fired combined cycle operations in the Carolinas. “We’re cleaning up the fleet,” Trent said. “The right path is a diverse fuel mix.”
He said Duke has spent $7bn on new air controls since 2005, with another $5bn-$6bn likely to be spent over the next decade.
He noted that the single biggest “game changer” for coal in recent years has been cheap natural gas, in part due to new shale gas plays. Duke is seeing gas prices now in the mid $3/mmBtu range, which is backing down coal plants.
Speaking during Coal-Gen at one of the various sessions on coal plant operations and maintenance issues was Brad Rudolph, a manager at Cliffside. He also talked about some flexibility issues. Like the idea that with solar energy becoming a major factor on the grid, coal plants may now have to run hard at night, when they traditionally don’t due to slack power demand at that time of the day, to sub in for solar plants that can’t produce any electricity at night.
Rudolph noted a “robust” program to test new, cheaper coals at plants in the Carolinas that normally burn Central Appalachia, which is getting increasingly more expensive due to severe coal reserve depletion in that heavily-mined region. He said that besides Illinois Basin coal, Northern Appalachia coal is also being tested. Powder River Basin coal is too costly and not being tested, he added. These new coals can cause problems, like with boiler slagging, but those issues can be solved with equipment changes, he noted.
Rudolph pointed to the fact that the older, still surviving Cliffside Unit 5, isn’t running much. He said its capacity factor in 2012 was about 24%, but it was that high only because of the need to test new coals, with the capacity factor likely to have been about 15% without that testing. He said Northern Appalachia coal is being tested at Cliffside.
U.S. Energy Information Administration data shows that coal suppliers to Cliffside earlier this year out of Northern Appalachia included CONSOL Energy‘s (NYSE: CNX) Bailey and Loveridge longwall operations, with Illinois Basin coal coming from the Galatia longwall mine in Illinois. More traditional Central Appalachian suppliers included Revelation Energy, Alpha Natural Resources (NYSE: ANR) and B&W Resources.
EIA data shows that at Belews Creek, suppliers earlier this year included CONSOL’s Bailey operation, and Alpha’s Emerald longwall mine, both in Northern Appalachia. Central Appalachia coal came from suppliers like Alpha and Arch Coal (NYSE: ACI).
At G.G. Allen, coal suppliers earlier this year were mainly Foresight Coal Sales out of the Shay #1 deep mine in Illinois, and CONSOL out of its Miller Creek operation in southern West Virginia (Central Appalachia).