Report finds compliance cost could exceed $3bn for Missouri plants

Power generators like Ameren Missouri are pursuing various alternatives, including new SO2 scrubbers and ultra-low-sulfur coal, said a May 2 report by Missouri Public Service Commission staff.

The PSC in August 2011 directed staff to lead a working group including utility, industrial, consumer, and environmental stakeholders, to investigate and file a report regarding the cost of compliance with federal environmental regulations, including the Cross-State Air Pollution Rule (CSAPR) and the Mercury and Air Toxics Standards (MATS).

“Based on analysis of this information, the overall capital cost to the electric utilities and potentially their customers would be in an approximate range of $1,981,000,000 to $3,276,000,000,” the report said. “This estimate is based on compliance with the rules that have been issued or are likely to be issued.”

The environmental regulations that were reviewed primarily affect coal-fired plants. The Missouri electric utilities utilize coal plants located in three states—Missouri, Kansas and Arkansas. Total Missouri-jurisdictional generating capacity for these units is about 9,000 MW. Total generating capacity for these units is about 13,700 MW.

At the initial workshop meeting in October 2011, information was presented by the electric utilities, the Midwest ISO, SPP and the Sierra Club. Information from these presentations is summarized below.

  • Union Electric Co. d/b/a Ameren Missouri – Recent environmental upgrades provide compliance improvements. The installation of scrubbers on Sioux Units 1 and 2 and fuel switching to ultra-low sulfur coal will provide environmental benefits. Compliance plans for SO2 include: utilization of ultra-low sulfur coal, banking SO2 credits, and evaluation of ultra-low sulfur coal vs. emissions control equipment for 2018 and beyond. Compliance plans for NOX include: aggressive tuning of units, additional over-fired air modifications, NOX allowance purchases and/or swap of SO2 for NOX allowances, or reduction in generation. Compliance for MATS could include: electrostatic precipitator upgrades, activated carbon injection (ACI), or fuel additives. Compliance with Clean Water Act rules could include: technology and biological studies; dependent on re-issued NPDES permits. Ameren Missouri is a unit of Ameren Corp. (NYSE: AEE).
  • Kansas City Power & Light Co. (KCP&L) and KCP&L Greater Missouri Operations Co. (GMO) – Recent environmental upgrades and new generating unit construction provide compliance improvements. Emissions projects include installation of: selective catalytic reduction (SCR) at La Cygne Unit 1; selective non-catalytic reduction (SNCR) on Sibley Units 1 and 2; SCR on Sibley Unit 3; SCR, scrubber, baghouse, and ACI at Iatan Unit 1; upgraded scrubbers on Jeffrey Energy Center Units 1-3; and Iatan Unit 2 with SCR, scrubber, baghouse, and ACI. “Additional compliance plans are in progress that affect these and other generating units. Compliance plans for SO2 include: scrubber installations, fuel switching, and reduction in generation. Compliance plans for NOX include: installation of SCR, installing low-NOX burners, reduction in generation, and increasing emission reductions from existing SCRs and SNCRs. Compliance for MATS could include: activated carbon injection, electrostatic precipitator upgrades, baghouse installation, dry sorbent injection, and fuel switching.” These companies are units of Great Plains Energy (NYSE: GXP).
  • Empire District Electric Co. – Recent environmental upgrades and new generating unit construction provide compliance improvements for Empire District Electric (NYSE: EDE). Plans included installation of: an SCR at Asbury; SCR, scrubber, baghouse and ACI at Iatan Unit 1; Iatan Unit 2 with SCR, scrubber, baghouse, and ACI; and Plum Point Unit 1 with SCR, scrubber, baghouse, and ACI. Compliance plans for SO2 include: scrubber installation, fuel switching, and retirement of units. Compliance for MATS could include: scrubber installation, baghouse installation, ACI, fuel switching, and unit retirements.
  • MISO – The MISO presentation was developed based on the proposed CSAPR, not the final CSAPR. While some changes were made in the final rule, most of the underlying assumptions remained constant. MISO estimated that about 12,600 MW of coal-fired unit capacity would be at-risk, necessitating capital investment of approximately $32.5bn to retrofit and/or replace the units. Energy prices could increase from $1 to $5 per MWh. Uncertainties could drive these numbers higher. Estimates for transmission system investments associated with the at-risk 12,600 MW would be about $880m. Based on MISO’s evaluation, the system reserve margin would not be maintained.
  • SPP – SPP performed reliability modeling evaluations of its system utilizing assumptions from EPA analysis. One of the modeling assumptions was removal of any SPP generating units which showed zero fuel consumption in the EPA analysis (114 generating units with aggregate nameplate capacity of 10,900 MW). Examples of concerns identified by the SPP analysis were: 16 overloads above 120% of emergency ratings for N-1 contingences, 93 circumstances with low voltage for N-1 contingencies, and 11 contingencies that would not solve within the model. Those scenarios represent circumstances under which drastic measures might be required. The results of the modeling showed FERC and North American Electric Reliability Corp. (NERC) violations for the summer 2012 peak conditions if EPA modeling assumptions were deployed.
  • Dogwood Energy LLC – The Dogwood Energy comments highlighted information regarding the Dogwood Energy facility near Pleasant Hill, Mo. It is a 650-MW, natural gas-fired combined-cycle plant. It operates at a high efficiency (50%) and low emissions. Missouri electric utilities have purchased power from Dogwood Energy in the past. Dogwood Energy anticipates that about half of its capacity and energy may be sold to municipal utilities and power pools by mid-year 2012 and by the end of 2012, Dogwood Energy’s ownership of the capacity at the Dogwood facility may be reduced to about one-third. Beyond 2013 or 2014, the Dogwood facility capacity may be completely allocated.
  • Sierra Club – The Sierra Club submitted detailed comments regarding: current EPA activities, utility resource planning, known or potential impacts on coal units, and recommendations regarding potential Commission actions. The Sierra Club recommended that the commission utilize an “Integrated Environmental-Compliance Planning” approach, noting that this would address several identified “shortcomings” in the current resource planning process.

Power generators update plans in 2012

Under Electric Utility Resource Planning rules, Ameren Missouri and Empire submitted an annual update report, and KCP&L and GMO submitted triennial compliance filings in 2012. These submittals were reviewed for information pertinent to this investigation. Summary information, as submitted by the utilities, from these plans is provided below.

  • Ameren Missouri – Ameren Missouri’s annual update included a section titled Environmental Compliance Analysis. Primary consideration was given to CSAPR compliance. Existing measures provide SO2 compliance through 2017. Installation of a flue gas FGD system at Rush Island was included as an option. Also, continued use of ultra-low sulfur coal and conversion of Meramec to natural gas were evaluated. Retirement of the Meramec plant was evaluated in combination with four supply side resource types: simple cycle gas turbines, combined cycle gas turbines, nuclear (small modular reactor), and wind coupled with simple cycle gas turbines. Compliance with the MATS rule includes electrostatic precipitator upgrades and ACI.
  • Empire – Empire is proceeding with its compliance plan to install a scrubber, fabric filter, and powder activated carbon injection at the Asbury plant (collectively referred to as the Asbury air-quality control system or AQCS). The installation should be completed by early 2015. The estimated cost is $112m to $130m. Upon the completion of the AQCS, Asbury Unit 2 will be retired. The compliance plan also includes transitioning Riverton Units 7 and 8 from coal to natural gas. These units are equipped to utilize either fuel, thus no appreciable capital expense is involved. By 2016, Riverton 12 may be converted from a simple cycle combustion turbine (142 MW) to a combined cycle unit (250 MW). Upon completion of this conversion, Riverton 7 and 8 (and 9) would be retired.
  • KCP&L and GMO – Their triennial filings include preferred plans for the addition of combined cycle, solar, and wind generating units (and noted that solar and wind additions could be obtained from power purchase agreements, purchase of renewable energy credits, or utility ownership). Retirement of three generating units is noted in the preferred plan; Montrose 1 in 2016 (KCP&L) and Sibley 1 and 2 in 2017 (GMO). For all three unit retirements, environmental regulations are noted as the drivers for these decisions. It is also noted that continuing developments regarding these regulations will be monitored to ensure these decisions remain prudent.

Impact of air rules seen as widespread and costly

“The current and pending EPA regulations have the potential to significantly impact the electrical generating capacity of Missouri,” the PSC staff report concluded. “This report primarily focuses on the coal-fired generating units that serve the Missouri customers of investor-owned utilities. … Other generating units such as natural gas-fired and nuclear may be impacted by these regulations to a lesser extent and are not addressed in this report. Control technologies are mature for some types of emissions and evolving for other types. From most perspectives, the two newest generating units (Iatan 2 and Plum Point 1) will not require extensive retrofits, if any. Iatan 1 and Hawthorne 5 generating units have retrofits in place that will satisfy most of the air emissions regulations. The remaining generating units may require extensive capital improvements as well as increased operating and maintenance expenses.”

Concerns about overall system reliability due to lack of generation due to retirements appear to be less significant than concerns about outage coordination. Outages may be required for decreased dispatch of existing generating units, retrofits, fuel switching, or environmental upgrades, the report said. These outages when occurring simultaneously could impact electrical systems, the report noted.

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.