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Coal-plant operators in the U.S. and Canada have announced plans to close a significant portion of their coal fleet. The following table contains a summary of coal plant retirements, by year of shutdown, tracked by Industrial Info. Data for 2010-2013 reflects actual plant closures while data for 2014-2017 shows the date of planned closures.
The 2015 MATS compliance deadline accounts for the sharp increase in planned retirements in that year. We expect EPA will grant some generators a one-year extension of the compliance deadline, which will push some projects to 2016. Also, reliability organizations will designate some coal-fired plants as “reliability/must run” generation in order to preserve grid stability, which we expect will help limit the number of closures in 2015 and 2016.
The decision to close a coal unit typically is driven more by the size of a unit than its age. Utilities are considering retrofitting units that are 450 MW or larger, but units smaller than that typically are being closed. Also, coal plants that are 50 or more years old are good candidates for shutdown, though we expect some of these older plants will remain open to ensure regional electric reliability.
Depending on the emissions being controlled, there is a wide range of costs to installing environmental compliance equipment. Controlling emissions of nitrogen oxides (NOx) can range from $15,000 to $25,000 per MW for Activated Carbon Injection (ACI) and Dry Sorbent Injection (DSI) projects. Reducing emissions of sulfur dioxide (SO2) with flue gas desulphurization (FGD) equipment vary from $175,000 to $200,000 per MW. Controlling particulate emissions with baghouses can cost from $75,000 to $100,000 per MW.
In 2013, construction started on several billion dollars of pollution-control projects at coal-fired power plants across the U.S., and Industrial Info sees that spend growing between 2014 and 2018. We expect construction of approximately $23.7 billion of pollution-control projects to begin at U.S. power plants over the next five years. The vast majority of this work will take place at coal-fired plants.
That number is sure to change during 2014, as it did throughout 2012 and 2013, in response to regulatory changes, as well as market conditions like reliability, electric demand growth and natural gas prices. Still, we expect pollution-control projects will continue to be a particularly active sector of the coal-fired power industry over 2014-2018.
Aside from closures and environmental retrofits, two other trends we see are a decline in scheduled maintenance outages at coal plants and an increase in unit cycling, mainly driven by low gas prices. When operators cycle coal plants, they are operating the equipment is ways it was not designed for, which places added stress on the equipment. Gas prices are expected to stay low for the foreseeable future, leading to more coal-plant cycling, which eventually will lead to equipment failure and unplanned outages.
Coal-state lawmakers in the House have drawn a line in the sand over EPA regulation of coal combustion residuals (CCR). Although companion legislation has not moved forward in the Senate, the EPA has deferred action on CCRs, since its initial proposed rule in mid-2010. But a September decision by a federal appeals court in Washington, D.C., instructed the EPA to move forward with a CCR rule. Observers expect no CCR action until mid-2014 at the earliest, after the agency issues its final Effluent Limitation Guidelines.
In a June 2010 proposed rule, the EPA for the first time proposed to end coal ash’s exemption from the Resource Conservation and Recovery Act (RCRA) and classify the waste in one of two ways. In one option, when the CCRs were destined for disposal in landfills or surface impoundments, the EPA would categorize CCRs as “special wastes” subject to regulation under subtitle C of RCRA. In the second option, the agency would regulate coal ash under subtitle D of RCRA, the section for non-hazardous wastes.
Classifying CCRs as a waste under RCRA would trigger a thorough operational review of each coal-fired generator every three years. The volume of wastewater and by-product produced by wet scrubbers is expected to pose a challenge for some operators.
Another emerging U.S. regulatory issue is an update of the Clean Water Act’s section 316(b) on cooling water intake systems, whose impact would go beyond coal to nuclear and even gas plants that cool their equipment with water from rivers, lakes and streams. The EPA was scheduled to publish its final rules updating this section of the CWA by November 2013. Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of power-plant cooling water intake structures reflect the best technology available for minimizing adverse environmental impact.
All of this regulatory activity and uncertainty has all but ended development of new-build coal-fired generation. Last year saw the completion of two coal-fired plants–the Edwardsport IGCC plant in Indiana and the Sandy Creek project in Texas–leaving only a small handful of projects still under construction. Over the next five years, we see about 2 GW of new-build coal plants kicking off construction.
While coal advocates rightly point to EPA regulations as a primary reason why new-build coal plant development has been stymied, market forces also play an important role. Overwhelmingly, utilities that need new generating capacity are building natural gas power plants, which were cheaper and faster to build and less expensive to run than coal plants. Also, gas plants have a smaller physical footprint compared to coal plants, another important consideration.
Industrial Info predicts that gas prices would have to more than double from their current level of about $4 per million British thermal units (MMBtu) cost for coal to compete economically with gas.
(You can read the rest of this report from Industrial Info Resources in the Turbomachinery Handbook 2014. That article gives an extensive overview of the natural gas, renewable and nuclear markets.)