Idaho commission staff backs Boardman shutdown accounting

Staff at the Idaho Public Utilities Commission agrees with a proposal by Idaho Power to use a balancing account to track the costs and benefits associated with the early shutdown in 2020 of the coal-fired Boardman plant in Oregon.

Staff, in a Jan. 13 report to the commission, also said it agrees with the company’s proposal to levelize incremental costs to calculate the revenue requirement for Boardman with a return on equity limitation. Staff believes a yearly review of the amounts booked into the balancing account will be sufficient and recommends the company file an annual report of the review with the commission.

Idaho Power, a unit of IDACORP Inc. (NYSE:IDA), in September 2011 asked the commission to accept its regulatory plan to account for the early shutdown of the Boardman plant. The utility did not ask the commission to approve rate recovery for future expenses associated with the Boardman shutdown at this time.

Boardman is a single-unit, coal-fired plant in north-central Oregon. Idaho Power owns 10%, or 58.5 MW (net dependable capacity) of Boardman. Portland General Electric (PGE) owns 65% of Boardman and operates the plant. Idaho Power currently depreciates Boardman using an end-of-life date of 2030.

Boardman is subject to the federal Clean Air Act, Oregon’s Regional Haze Plan, and Oregon’s Utility Mercury Rule. After analyzing each of the Boardman-related control technologies and associated deadlines required by the legal requirements, plus a consent decree in a federal court case, PGE determined that closing Boardman in 2020 would strike a good balance between the key risk drivers of natural gas and CO2 prices, while maintaining system reliability at a relatively low cost.

Under the 2020 closure plan, the owners of the plant would still, in the interim, need to install new burners to reduce NOx emissions by nearly 50% and use lower sulfur coal to reduce SO2 emissions by 50%.

Idaho Power proposed a three-step plan to respond to the proposed 2020 closure. It would perform, in early 2012, a depreciation study and ask for new depreciation rates for all plant investment, including Boardman, to become effective June 1, 2012. It would also establish a balancing account to track closure-related incremental costs and benefits, and ask the commission, in early 2012, to authorize the company to increase customer rates to recover Boardman decommissioning costs, with rates to take effect June 1, 2012.

Oregon’s Utility Mercury Rule required installation of controls by July 1, 2012. PGE decided to meet the requirements using activated carbon injection (ACI) instead of more expensive fabric fiter equipment. PGE received approval from the Oregon Department of Environmental Quality (ODEQ) and installed the ACI controls during the spring of 2011.

In 1999, the EPA adopted a Regional Haze (RH) rule for utilities as part of the Clean Air Act. The EPA left it up to the states to develop strategies and make reasonable progress to reduce visibility impairment in protected areas. As an older facility that fits the profile as a major contributor of emissions in Class I areas, Boardman was subject to a Best Available Retrofit Technology (BART) analysis and was evaluated to see if retrofitting with controls was feasible and cost effective. Besides cost and meeting federal emission requirements, part of the feasibility criteria considered the need to meet electricity demand in PGE and other Boardman owners’ service areas. The plan that was ultimately approved by ODEQ and included in the State Implementation Plan (SIP) for RH BART and approved by the EPA covers four major steps.

One step is that the plant will cease operation by Dec. 31, 2020. This eliminates all “reasonable progress” requirements that would have been needed to satisfy RH BART, specifically investments in NOx controls to obtain 0.07 lb/mmBtu levels by 2018.

A second step is low NOx burners and over-fire air to control NOx to 0.23 lb/mmBtu levels. These controls have already been installed.

A third step is installation of dry sorbent injection to control SO2 to 0.40 lb/mmBtu levels by 2014 and 0.30 lb/mmBtu levels by 2018.

The fourth step is the already-completed installation of activated carbon injection to control mercury to 0.6 lb/TBtu levels by July 2012. This control is for compliance with Oregon’s Utility Mercury rule, although it was included in the SIP submitted and approved by the EPA.

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.