PacifiCorp has coal unit switch to gas, Carbon shutdown, in the works

PacifiCorp currently plans to convert the coal-fired Naughton Unit 3 in Wyoming to a natural gas-fueled unit anticipates retiring the Carbon coal-fueled generating facility in Utah in early 2015, the company said in its March 1 Form 10-K annual report.

While the final Mercury and Air Toxics Standards (MATS) are still under review by PacifiCorp, the company believes that its emissions reduction projects completed to date or currently permitted or planned for installation, including scrubbers, baghouses and electrostatic precipitators, are consistent with the MATS and will support PacifiCorp’s ability to comply with the final rule’s standards for acid gases and non-mercury metallic hazardous air pollutants.

PacifiCorp said it will be required to take additional actions to reduce mercury emissions through the installation of controls or use of sorbent injection at certain of its coal-fueled facilities and otherwise comply with the final rule’s standards.

PacifiCorp currently anticipates that retiring the Carbon in early 2015 will be the least-cost alternative to comply with the MATS and other environmental regulations. PacifiCorp continues to assess compliance alternatives and potential transmission system impacts that could otherwise impact PacifiCorp’s ultimate decision with respect to the Carbon facility, including timing of retirement and decommissioning.

Incremental costs to install and maintain emissions control equipment at PacifiCorp’s coal-fueled facilities and any requirement to shut down what have traditionally been low cost coal facilities will likely increase the cost of providing service to customers. In addition, numerous lawsuits are pending against the MATS in a federal appeals court, which may have an impact on PacifiCorp’s compliance obligations and the timing of those obligations, the Form 10-K noted.

Regional haze rule has wider impact than MATS

The U.S. Environmental Protection Agency has also initiated a regional haze program. In accordance with the federal requirements, states are required to submit State Implementation Plans (SIPs) that address emissions from sources subject to best available retrofit technology (BART) requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.

Utah: The state of Utah issued a regional haze SIP requiring the installation of SO2, NOx and particulate controls on the coal-fired Hunter Units 1-2 and Huntington Units 1-2. In December 2012, the EPA approved the SO2 portion of the Utah regional haze SIP and disapproved the NOx and particulate portions. Certain groups have appealed the EPA’s approval of the SO2 portion. The date for appealing the disapproval of the NOx and particulate portions is March 25. In addition, and separate from the EPA’s approval process and related litigation, the Utah Division of Air Quality is doing an additional BART analysis for Hunter Units 1-2 and Huntington Units 1-2, which will be provided to the EPA as a supplement to the existing Utah SIP. It is unknown whether and how this supplemental analysis will impact the EPA’s approval and disapproval of the existing SIP.

Wyoming: In Wyoming, the state issued two SIPs requiring the installation of SO2, NOx and particulate controls on certain PacifiCorp coal facilities in Wyoming. The EPA approved the SO2 SIP in December 2012, but initially proposed to disapprove portions of the NOx and particulate SIP and instead issue its own Federal Implementation Plan (FIP). The EPA proposed to approve:

  • the installation of selective catalytic reduction (SCR) equipment and a baghouse at Naughton Unit 3 by Dec. 31, 2014;
  • the installation of SCR at Jim Bridger Unit 3 by Dec. 31, 2015; and
  • to approve the installation of SCR  at Jim Bridger Unit 4 by Dec. 31, 2016.

The EPA proposed to disapprove the NOx and particulate SIP for Jim Bridger Units 1-2 and instead accelerate the installation of SCR equipment to 2017 from 2021 and 2022, but agreed to accept comment on maintaining the original schedule as the state proposed. In addition, the EPA proposed to reject the SIP for the Wyodak facility and Dave Johnston Unit 3 and require the installation of selective non-catalytic reduction (SNCR) equipment within five years, as well as require the installation of low-NOx burners and overfire air systems at Dave Johnston Units 1 and 2. Since the EPA’s initial proposal, the EPA has withdrawn its proposed actions on the SIP and its proposed FIP and has indicated its intent to re-propose action of the Wyoming NOx and particulate matter SIP by March 2013, and take final action by September 2013. In the meantime, certain groups have appealed the EPA’s approval of the SO2 SIP.

Arizona: In Arizona, the state issued a regional haze SIP requiring, among other things, the installation of SO2, NOx and particulate controls on Cholla Unit 4. The EPA approved in part, and disapproved in part, the Arizona SIP and issued a FIP for the disapproved portions. PacifiCorp appealed to the U.S. Ninth Circuit Court of Appeals regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP as it relates to their interests. The Ninth Circuit has not made any decisions on these appeals.

Other cases are pending before the U.S. Tenth Circuit Court of Appeals with regard to similar appeals of FIPs issued by the EPA in New Mexico and Oklahoma, PacifiCorp noted. Until the EPA takes final action in each state and decisions have been made on each appeal, PacifiCorp cannot fully determine the impacts of the Regional Haze regulation on its generating facilities.

PacifiCorp spends heavily on emissions projects

The company has:

  • in 2012 spent $75m on existing facilities for installation or upgrade of SO2 scrubbers, low-NOx burners and particulate control systems;
  • in 2011 spent $189m for installation or upgrade of SO2 scrubbers, low-NOx burners and particulate systems, including costs for projects that were placed in service in the spring and fall of 2011; and
  • in 2010 spent $347m, including costs for Dave Johnston Unit 3, which includes an SO2 scrubber that was placed in service in May 2010, as well as low-NOx burners and costs for installation or upgrade of SO2 scrubbers on various other generating facilities.

The company is projecting environmental capital spending of $141m in 2013, $173m in 2014 and $130m in 2015, all on unnamed projects.

PacifiCorp’s coal plants, with total net capacity and PacifiCorp’s share of ownership of that capacity, are:

  • Jim Bridger 1-4 (Wyoming), 2,111 MW (1,407 MW);
  • Hunter 1-3 (Utah), 1,352 MW (1,147 MW);
  • Huntington 1-2 (Utah), 909 MW (909 MW);
  • Dave Johnston 1-4 (Wyoming), 762 MW (762 MW);
  • Naughton 1-3 (Wyoming), 687 MW (687 MW);
  • Cholla 4 (Arizona), 395 MW (395 MW);
  • Wyodak 1 (Wyoming), 335 MW (268 MW);
  • Carbon 1-2 (Utah), 172 MW (172 MW);
  • Craig 1-2 (Colorado), 863 MW (166 MW);
  • Colstrip 3-4 (Montana), 1,480 MW (148 MW); and
  • Hayden 1-2 (Colorado), 446 MW (78 MW).

PacifiCorp has interests in Deer Creek, Bridger and Trapper mines

PacifiCorp has interests in coal mines that support some of its coal-fueled facilities and operates the Deer Creek longwall mine in Utah, and the Bridger surface and Bridger underground coal mines in Wyoming. These mines supplied 30%, 28% and 29% of PacifiCorp’s total coal requirements in 2012, 2011 and 2010, respectively. The remaining coal requirements are acquired through long- and short-term third-party contracts. PacifiCorp also operates the Cottonwood prep plant and Wyodak Coal Crushing Facility.

PacifiCorp said the Bridger surface mine had 29 million tons (representing PacifiCorp’s two-thirds share of this operation) of recoverable coal left as of the end of 2012, and the Bridger deep mine had 46 million recoverable tons (again, this is two thirds of the total). Idaho Power owns the other one-third of the Bridger mines and the adjacent Jim Bridger power plant. The Deer Creek longwall mine in Utah had 26 million tons of recoverable coal as of the end of 2012. The Trapper strip mine in Colorado had 6 million tons (based on PacifiCorp’s 21% ownership).

In June 2011, Fossil Rock, a subsidiary of PacifiCorp, acquired the Cottonwood coal reserve lease in Emery County, Utah, from Arch Coal (NYSE: ACI). The coal lease contains an estimated 47 million tons of recoverable coal available to supply PacifiCorp’s coal-fueled facilities in Utah in the future.

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.