PRB coal will serve 47% of the surviving fleet, steady with 2014’s total share but above 44% in 2007, before the U.S. shale gas production boom and closures in anticipation of the U.S. Environmental Protection Agency’s (EPA) Mercury and Air Toxics Standards (MATS) ramped up. ILB and NAPP will see bigger market gains, rising to 13% and over 14%, respectively, from 7.9% and 9.7% in 2007.
The high-cost Central Appalachia (CAPP) region will be the biggest loser, with its portion of U.S. power sector coal deliveries looking to fall to 6.1% after all announced closures and conversions are completed from 6.5% in 2014 and a little more than 15% in 2007. Demand displacement by natural gas has affected all U.S. coal markets, but CAPP has been the most vulnerable. Average production costs in the basin of around $60/ton or more than $10/ton above current spot prices, according to SNL Energy over-the-counter market surveys.
CAPP coal does not become more competitive on a spot basis until gas goes above $4 per million Btu (MMBtu), but futures are trading just below $3/MMBtu. ILB coal has a tough time competing with gas until prices for the latter reach $3.50/MMBtu to $3.75/MMBtu, but PRB coal is more attractive even when gas falls to $2.50/MMBtu to $2.75/MMBtu, Peabody Energy’s newly elected CEO Glenn Kellow said on the company’s April 23 earnings call.
Producers of more competitive U.S. coals expect their market share — and outright sales — to potentially grow further. Peabody, whose U.S. mines are largely based in the PRB and ILB, expects demand for both coals to rebound after MATS-related unit retirements subside past 2016. “By 2017, we expect coal’s share of U.S. electricity generation to return to nearly 40%. And PRB and ILB demand is projected to increase, as natural gas prices recover and higher coal plant utilization and basin switching offset expected retirements,” Kellow said. Peabody estimates combined demand for PRB and ILB coal will grow by 50 million tons to 70 million tons between 2014 and 2017. Company Executive Vice President and CFO Michael Crews added that the PRB is the “go-to source, and one that we’re pleased to be the No. 1 producer in.”
Although it will remain the single biggest source of U.S. coal, optimism on the PRB’s long-term prospects may be overdone. Southern Co. is retiring or converting a large amount of its coal-fired generating capacity to burn natural gas, which could limit the PRB’s penetration of the southeastern utility market.
PRB Coal Users’ Group Executive Director Randy Rahm told SNL Energy that Southern had been considering burning PRB coal at its Greene County plant in Alabama before gas became more attractive. Southern expects to stop using coal at units 1 and 2 of the Greene County plant no later than April 2016 and start operating them solely on gas. Southern could switch to using PRB at one of its other units. The company said May 7 that it was “evaluating its plans” for unit 3 totaling 225 MW at the Barry plant in Alabama, which is currently unavailable for generation. Rahm said Southern was considering using PRB coal there. In early 2015, the Barry plant mainly received imported coal from Colombia, according to U.S. Energy Information Administra-tion data.
Southern did not confirm whether it was considering using PRB coal at Barry, telling SNL Energy it is “waiting for more clarity on the future environmental regulatory front to make final decisions on the future status of Barry 3. [Alabama Power] continually evaluates its fuel mix to ensure the most economic value for our customers.” The company ceased using coal at units 1 and 2 of Barry in April, which will be available on a limited basis with gas as the fuel source.
Efforts by Illinois legislators to incentivize use of in-state coal by local generators could also limit the PRB’s prospects. Illinois Rep. John Bradley, D-Marion, told SNL Energy that he and a group of other state lawmakers hope to advance bills to overturn a state regulation that makes it cheaper for Illinois generators to use PRB coal railed in from the West than locally produced ILB coal. Illinois last year received about 10.4 million tons of coal, 84% of it from Wyoming.
All major coal-producing regions will lose demand to pending plant retirements, but NAPP is the least exposed of the major basins. SNL Energy estimates that less than 4% of NAPP domestic coal deliveries last year went to units that have retired or are scheduled to stop burning coal. The only other basins with lower exposure on a percent basis are Gulf Coast and northern U.S. lignite regions, which largely serve mine-mouth plants, and the small southern Wyoming market, which only shipped 11.4 million tons to domestic generators in 2014.
Part of NAPP’s advantage also lies in its proximity to major customers. The basin serves large scrubbed coal plants within its production footprint of Ohio, Pennsylvania, and other parts of the Midwest and mid-Atlantic. “I think the demand side for ILB and NAPP has been pretty much established, and it’s going to be flat for a while,” Alliance Resource Partners LP President and CEO Joe Craft said on an April 29 earnings call.
Alliance reported in a May 22 investor presentation that domestic utility consumption of eastern U.S. bituminous coals will “stabilize” at around 250 million tons through 2020. More than 100 million tons each will come from the ILB and NAPP, with the rest from CAPP.
CONSOL Energy, which has narrowed its steam coal assets to large Pennsylvania longwall mines, is one of the least exposed of publicly traded coal companies to plant retirements. About 6% of CONSOL’s coal sales last year were to retiring or closed units.
Despite the PRB’s dominant role in U.S. coal markets, its sheer size means a large chunk of PRB coal-fired capacity is set to close, which will hit some producers harder than others. A little more than 12% of Peabody’s coal sales in 2014 went to units that are closing or converting, compared with around 10% each for Arch Coal and Alpha Natural Resources and 7% for Cloud Peak Energy.
