Idaho Power looks at a future without coal capacity

The Idaho Power unit of IDACORP (NYSE: IDA) is looking at whether shutting down or exiting coal capacity is a better alternative than retrofitting that capacity with new air emissions controls, said IDACORP in its Nov. 1 Form 10-Q quarterly report.

One factor driving that review is that on May 21, the Oregon Public Utility Commission (OPUC) acknowledged Idaho Power’s 2011 integrated resource plan (IRP). The OPUC directed Idaho Power to, among other things, include in its next IRP update an evaluation of environmental compliance costs for existing coal-fired plants. Idaho Power was directed to investigate whether there is “flexibility in the emerging environmental regulations” that would allow the utility to “avoid early compliance costs by offering to shut down individual units prior to the end of their useful lives.” The order also directed Idaho Power to conduct further plant-specific analysis to determine whether this trade-off would be in the ratepayers’ interest. Idaho Power is currently preparing its 2013 IRP, the Form 10-Q noted.

Operation of Idaho Power’s jointly-owned coal-fired power plants – Boardman in Oregon, Jim Bridger in Wyoming and North Valmy in Nevada – is subject to a broad range of federal, state, and local environmental laws and regulations, both pending and enacted. Idaho Power expects that these laws and regulations, which will continue to increase the cost of operating coal-fired plants, will necessitate installation of more pollution control devices at existing generating plants, or result in Idaho Power discontinuing operation of certain coal-fired plants where operation becomes uneconomical.

In connection with its IRP process, Idaho Power has been conducting cost studies and scenario analysis to assess these investment decisions, using a range of fuel pricing assumptions, plant upgrade and retirement costs, environmental regulation assumptions, replacement costs, and other factors in that assessment. Idaho Power plans to publish the results of its most recent analysis with its 2011 IRP update to be filed with the OPUC in November, and invites interested parties to review and comment on the results of the analysis.

Idaho Power is already heading away from coal. The Langley Gulch power plant in Idaho, a gas-fired combined-cycle combustion turbine plant with a summer nameplate capacity of about 300 MW and a winter capacity of around 330 MW, was placed in service on June 29.

Also, in December 2010, the Oregon Environmental Quality Commission approved a plan to cease coal-fired operations at the 585-MW Boardman power plant not later than Dec. 31, 2020. Idaho Power owns a 10% interest in the plant.

Idaho Power ready to up its goal for CO2 reductions

While there is currently no national mandatory greenhouse gas reduction requirement, Idaho Power continues to prepare for potential legislative and/or regulatory restrictions on emissions. In September 2009, IDACORP’s and Idaho Power’s boards of directors approved guidelines that established a goal to reduce Idaho Power’s resource portfolio’s average CO2 emission intensity for the 2010-2013 time period to a level of 10% to 15% below Idaho Power’s 2005 CO2 emission intensity of 1,194 lbs CO2/MWh. 

“As of the date of this report, Idaho Power is on-track to exceed the CO2 emission intensity reduction goal it established in 2009,” said the Form 10-Q. “The combination of effective utilization of hydroelectric projects, above average stream flows during 2011, reduced usage of coal-fired facilities, and addition of the Langley Gulch natural gas-fired power plant have positioned the company to extend its CO2 intensity reduction goal period for an additional two years, targeting an average reduction of 10 to 15 percent below its 2005 levels for the entire 2010 through 2015 time period. Idaho Power management plans to recommend to its board of directors that the board approve the extension of the intensity reduction goal.”

As for the impacts of various air rules:

  • Mercury and Air Toxics Standards (MATS): In March 2011, the EPA released the proposed MATS to control emissions of mercury and other hazardous air pollutants (HAPs) from coal- and oil-fired electric utility steam generating units (EGUs) under the federal Clean Air Act (CAA). In the same notice, the EPA further proposed to revise the new source performance standards (NSPS) for fossil fuel-fired EGUs. Both the proposed HAPs regulation and the associated NSPS revisions were finalized on Feb. 16. For the revised NSPS, for EGUs commencing construction of a new source after publication of the final rule, the EPA has established amended emission limitations for particulate matter, SO2, and NOx. Mercury continuous emission monitoring systems have been installed on all of the coal-fired units at the Jim Bridger, Boardman, and Valmy plants. Idaho Power has reviewed the final rule and is in the process of determining how to meet these regulations at these plants. The compliance deadline for the new MATS could be as early as 2015, though EPA has suggested that a one-year extension may be available for utilities where justified.
  • National Ambient Air Quality Standards (NAAQS) for NOx: In February 2010, the EPA revised the NAAQS. In connection with the new NAAQS, in February the EPA issued a final rule designating all of the counties in Idaho, Nevada, Oregon, and Wyoming where Idaho Power owns or has an interest in a natural gas- or coal-fired power plant as “unclassifiable/attainment” for NO2. The EPA indicated it will review the designations after 2015, when three years of air quality monitoring data are available, and may formally designate the counties as attainment or non-attainment for NO2. A designation of non-attainment may increase the likelihood that Idaho Power would be required to install costly pollution control technology at one or more plants.
  • NAAQS for Particulate Matter: On June 29, the EPA published proposed revisions to the primary and secondary NAAQS for fine particulate matter (PM2.5). The EPA also proposed revisions to the prevention of significant deterioration permitting program with respect to the proposed NAAQS revisions. The EPA has stated that it plans to finalize the air quality standards by December, the Form 10-Q noted. The EPA’s proposed primary standard for fine particles was between 12 and 13 micrograms per cubic meter (µg/m3), calculated as a three-year average. The EPA proposed to retain the exiting 24-hour primary standard for fine particulate matter at 35 µg/m3. The EPA proposed to remain unchanged the secondary standards for PM2.5 and would be identical to the primary standards. Once finalized, the revisions would trigger a process under which states will make recommendations to the EPA regarding designations of attainment or non-attainment. States also will be required to review, modify, and supplement their existing state implementation plans (SIP), which could require the installation of additional controls and requirements for Idaho Power’s coal-fired plants, depending on the level ultimately finalized. The revised NAAQS would also have an impact on the applicable air permitting requirements for new and modified facilities. The EPA has stated that it plans to issue nonattainment designations by late 2014, with states having until 2020 to comply with the standards.
  • Clean Air Act-Regional Haze Rules: Coal-fired utility boilers are subject to regional haze-best available retrofit technology (RH BART) if they were built between 1962 and 1977 and affect any Class I areas. This includes all four units at the Jim Bridger plant and also the Boardman plant. In May, the EPA proposed to partially reject Wyoming’s regional haze SIP for NOx reduction at the Jim Bridger plant, instead proposing to substitute the EPA’s own RH BART determination and FIP. The EPA’s primary proposal would result in an acceleration of the installation of selective catalytic reduction (SCR) at Bridger Units 1 and 2 to within five years after the FIP, or a SIP revised to be consistent with the proposed FIP, is adopted by the EPA. The EPA has stated that it plans to adopt the FIP, or approve the revised Wyoming SIP, by late 2012. The EPA recognized that this accelerated schedule may create a hardship for the owners of Jim Bridger plant (the other owner is PacifiCorp), including Idaho Power and its customers, and has requested the submission of comments on whether the Wyoming schedule that would not require installation of the SCR on Bridger Units 1 and 2 until 2021 and 2022, respectively, is more appropriate. In August, Idaho Power and PacifiCorp, among other interested parties, submitted comments to the EPA in support of the Wyoming SIP and requesting that the SIP be approved without amendment. Bridger has four units, each with 706 MW (nameplate) of capacity.
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.