Arizona seeks input on SCR/shutdown options for Coronado Unit 1

The Arizona Department of Environmental Quality is taking comment until Aug. 23 on its intent to approve an air permit revision sought by the Salt River Project that would require the installation of either selective catalytic reduction (SCR) on the coal-fired Coronado Unit 1 or the unit’s eventual shutdown.

Coronado Generating Station (CGS) consists of two coal-fired units, Units 1 and 2, which are subject to the Best Available Retrofit Technology (BART) requirements under the U.S. Environmental Protection Agency’s regional haze program. SRP is proposing an alternative (called the “BART Alternative”) as a revision to the regional haze State Implantation Plan (SIP). This permit revision incorporates SRP’s two BART Alternative operating strategies:

  • Either install and commence operation of SCR on Unit 1 by Dec. 31, 2029, or
  • Shut down Unit 1 by Dec. 31, 2029.

For the period starting in Dec. 5, 2017 and ending no later than Dec. 31, 2029, both of the BART Alternative operating strategies will include a Unit 1 interim BART Alternative operating strategy {interim operating strategy that will involve four seasonal curtailment options for Unit 1. These options entail varying durations of curtailment of Unit 1 and are dependent on the demonstrated NOx emissions rate of Unit 1 and the SO2 emissions rate of Unit 1 and Unit 2.

In February 2011, the Arizona DEQ submitted to the Environmental Protection Agency the state’s initial Regional Haze SIP for the first planning period of the regional haze program. This submission included BART determinations for CGS Unit 1 and Unit 2. EPA published its notice of final rule-making approving Arizona’s SO2 and PM10 BART determination, disapproving Arizona’s NOx BART determination, and establishing a NOx BART Federal Implementation Plan (FIP) for Units 1 and Unit 2, the two BART-eligible electric generating units at Coronado, in December 2012.

The FIP imposed an average NOx emission limit of 0.065 pound per million British thermal unit applicable across both units on a 30-boiler-operating-day average basis, with a final compliance date of Dec. 5, 2017. The rule also required SRP to install SCR systems on Unit 1 and Unit 2 by the compliance date of Dec. 5, 2017. Unit 2 is already equipped with SCR (commenced operation in 2014) through a consent decree between SRP and EPA.

SRP filed a petition for administrative reconsideration of the NOx BART determination with EPA in February 2013. EPA approved this request and prepared a revised NOx FIP, which was signed by EPA on March 29, 2016, and published in the Federal Register on April 13, 2016. This action revised the NOx limits for Unit 1 to 0.065 lb/MMBtu and for Unit 2 to 0.080 lb/MMBtu, with both limits to be met on a 30-boiler-operating-day average, and maintained the initial compliance date of Dec. 5, 2017.

EPA released its proposed Carbon Pollution Emission Guidelines for Existing Electric Utility Generating Units, commonly referred to as the Clean Power Plan (CPP), in June 2014. This rule was published in August 2015. The final rule gave states until September 2018 to submit final plans outlining how they will meet the requirements. On Feb. 9, 2016, the U.S. Supreme Court granted a stay, halting implementation of the CPP pending the resolution of legal challenges to the program in court. This action has created additional uncertainty for SRP with respect to the nature and timing of its compliance obligations for the CGS units.

Effectiveness of this permit revision is contingent on approval as part of the Regional Haze SIP for Arizona and will be effective on the date of final action by EPA, provided that such final EPA action also revokes or rescinds EPA’s FIP.

Seasonal curtailments are designed to achieve a NOx limit of 0.065 lb/MMBtu on a 30-boiler-operating-day average. The interim operating strategy includes specified curtailment periods for CGS Unit 1. In addition, three of the four interim operating strategies involve a reduction in the SO2 emission rate at both Unit 1 and Unit 2. One of the strategies also includes a NOx emission rate below the permit limit for Unit 1. In each year, the length of required curtailment period for Unit 1 is dependent on the NOx emissions performance of Unit 1 and SO2 emissions performance of both Unit 1 and Unit 2.

H2SO4 emissions, related to SO2 emissions, can be controlled to varying degrees using particulate matter (PM) and flue gas desulfurization (FGD) control systems and low-sulfur coals. CGS Unit 1 is already well controlled for PM, SO2, and H2SO4 by the following systems in place: 60% to 100% low-sulfur Powder River Basin (PRB) coal, hot-side electrostatic precipitator (ESP), and wet FGD. Additional H2SO4 controls that are potentially applicable include:

  • Coal Switching, Washing, and Processing;
  • Flue Gas Conditioning;
  • Reagent/Sorbent Injection; and
  • Wet Electrostatic Precipitation.

As noted, fuel switching to a lower-sulfur coal can be one option for reducing emissions of H2SO4. CGS Unit 1 currently fires subbituminous blends, but has historically used bituminous and subbituminous coals, and may continue to do so in the future. Western bituminous coal has sulfur concentrations ranging from 1.0 to 1.5 percent with a heating value range of 9,200 to 12,000 British thermal unit (Btu) per pound. Sub-bituminous/ PRB coal has sulfur concentrations below 0.5 percent with a heating value range of 8,000 to 8,600 Btu per pound. Switching to 100% PRB subbituminous coal could potentially reduce boiler SO3 emissions. Currently, CGS Unit 1 burns 60 to 100 percent PRB coal. The decision of the type and amount of coal to burn is very complex, the DEQ noted. The reliability of PRB deliveries is a legitimate and significant concern. In order to minimize potential issues associated with dependable fuel delivery and to ensure economical long-term supply of fuel, CGS must keep the option to use western bituminous coals. Thus switching to 100% PRB subbituminous coal is not considered an available H2SO4 control option.

Units 1 and 2 at Coronado generate approximately 762 MW) (net). Units 1 and 2 were completed and started operation in the 1979-1980 period. Units 1 and 2 are dry-bottom turbo-fired boilers with a net rated output of 380 MW and 382 MW, respectively.

The public notice period on the revision extends to Aug. 23. ADEQ will be holding a public hearing on Aug. 23 at St. John’s High School Auditorium in St. John, Arizona.

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.