Idaho Power, NV Energy mull early retirement of North Valmy coal plant

Idaho Power is looking at the need for further selective catalytic reduction (SCR) installations at two units of the coal-fired Jim Bridger power plant in Wyoming and at the early retirement of the North Valmy coal plant in Nevada.

Idaho Power on June 30 filed a 2015 Integrated Resource Plan (IRP) with the Idaho Public Utilities Commission that evaluates the 20-year planning period from 2015 through 2034. During this period, load is forecasted to grow by 1.2% per year for average energy demand and 1.5% per year for peak-hour demand. Total customers are expected to increase to 711,000 by 2034 from 515,000 in 2014. Additional company-owned resources will be needed to meet these increased demands.

Idaho Power owns and operates 17 hydroelectric projects, three natural gas-fired plants, one diesel-powered plant, and shares ownership in three coal-fired facilities. Hydroelectric generation is a large part of Idaho Power’s generation fleet; however, hydroelectric plants are subject to variable water and weather conditions.

The IRP’s action plan includes:

  • 2015–2018, Boardman to Hemingway (B2H) power line, Ongoing permitting, planning studies, and regulatory filings. The project involves a new, single-circuit 500-kV transmission line approximately 300 miles long between the proposed Longhorn Station in the Boardman, Oregon, area and the Hemingway Substation in southwest Idaho.
  • 2015–2018, Gateway West, Ongoing permitting, planning studies, and regulatory filings. The Gateway West transmission line is a joint project between Idaho Power and PacifiCorp d/b/a Rocky Mountain Power to build and operate approximately 1,000 miles of new transmission lines from the planned Windstar Substation near Glenrock, Wyoming, to the Hemingway Substation near Melba, Idaho.
  • 2015–2019, Energy efficiency, Continue the pursuit of cost-effective energy efficiency. The forecast reduction for 2015–2019 programs is 84 average megawatts (aMW) for energy demand and 126 MW for peak demand.
  • 2015–2016, Coordinate with government agencies on implementation planning for Clean Air Act Section 111(d) (Clean Power Plan).
  • 2015, Shoshone Falls hydropower facility, File to amend FERC license regarding 50-MW expansion.
  • 2015, Jim Bridger Unit 3, Complete installation of SCR emission-control technology for NOx.
  • 2015–2016, Shoshone Falls, Study options for a smaller upgrade ranging in size up to approximately 4 MW.
  • 2016, Jim Bridger Unit 4, Complete installation of SCR.
  • 2016, North Valmy units 1 and 2, Continue to work with plant co-owner NV Energy to synchronize depreciation dates and determine if a date can be established to cease coal-fired operations.
  • 2017, Shoshone Falls, Commence construction of smaller upgrade.
  • 2017, Jim Bridger units 1 and 2, Evaluate the installation of SCR technology for units 1 and 2 at Jim Bridger in the 2017 IRP.
  • 2019 Shoshone Falls, On-line date for smaller upgrade during first quarter.

Since 1990, Idaho Power’s total nameplate generation has increased from 2,635 MW to 3,594 MW. Idaho Power’s newest resource addition is the 318-MW Langley Gulch CCCT. This highly efficient, natural gas-fired power plant is located in the western Treasure Valley in Payette County, Idaho. The plant became commercially available in June 2012.

IRP looks at options for coal plants under the Clean Power Plan

As for coal facilities:

  • Idaho Power owns one-third, or 771 MW (generator nameplate rating), of the Jim Bridger coal-fired plant located near Rock Springs, Wyoming. The Jim Bridger plant consists of four generating units. PacifiCorp has two-thirds ownership and is the operator of the Jim Bridger facility.
  • Idaho Power owns 50%, or 284 MW (generator nameplate rating), of the North Valmy coal-fired plant located near Winnemucca, Nevada. The North Valmy plant consists of two units. NV Energy has 50% ownership and is the operator.
  • Idaho Power owns 10%, or 64.2 MW (generator nameplate rating), of the Boardman coal-fired plant located near Boardman, Oregon. The plant consists of a single generating unit. Portland General Electric (PGE) has 90% ownership and is the operator. The 2015 IRP assumes Idaho Power’s share of the Boardman plant will not be available after Dec. 31, 2020. The 2020 date is the result of an agreement reached between the Oregon Department of Environmental Quality (ODEQ), PGE, and the EPA related to compliance with Regional Haze Best Available Retrofit Technology (RH BART) rules on particulate matter, sulfur dioxide (SO2), and nitrogen oxide (NOx) emissions.

Said the IRP: “The 2015 IRP examines the EPA’s proposed CAA Section 111(d) regulation and the future of Idaho Power’s ownership share of the Jim Bridger and North Valmy coal-fired power plants. With the exception of the Status Quo portfolio, all other portfolios analyzed evaluate alternatives to continued investment in the coal units and/or the impact of reducing generation from fossil-fueled power plants to comply with uncertain environmental regulations. The optimization of coal unit shutdown alternatives using computer modeling tools will not be possible until the proposed CAA Section 111(d) regulation is finalized sometime in the second half of 2015. It is possible to identify trends in the modeling results that indicate a portfolio with an earlier North Valmy unit shutdown coupled with the completion of the B2H project performs well on a 20-year net-present-value (NPV) basis.

“The early retirement of an asset requires accelerating the recovery of the remaining investment in that asset. This increases the cost in the early years in exchange for longer-term savings. This is conceptually similar to repaying a home mortgage early. Over the shortened life of a loan, the total payments will be less, but in the near term the monthly payment will be higher. The same is true when contemplating early retirement of North Valmy or Jim Bridger units. For example, a North Valmy 2019 early shutdown will cost approximately $95 million more between 2015 and 2019 but save approximately $181 million in fixed O&M, capital investment, and finance costs compared to a 2031 to 2034 retirement (in nominal dollars). Unlike the home mortgage example, a coal unit will have little value at the decommissioning date, and it is likely another resource investment will be required.”

The preferred portfolio selected is portfolio P6(b), which includes the retirement of the North Valmy plant at year-end 2025 and the completion of the B2H project in 2025. The close linking of these resource actions suggests an earlier completion date of the B2H project could accelerate the decommissioning of the North Valmy plant, Idaho Power noted. Portfolio P6(b) also includes the addition of 60 MW of demand response and 20 MW of ice-based TES in 2030. In 2031, portfolio P6(b) also adds a 300 MW combined-cycle combustion turbine (CCCT).

These resource additions late in the planning period address projected needs for resources providing peaking capability and system flexibility. With the expected long-term expansion of variable energy resources, the need for dispatchable resources that provide system flexibility will also increase, the utility said.

The earliest that both North Valmy units would be retired under any of the portfolios is the end of 2019.

Idaho Power is proposing a pilot project to investigate the benefits of using ice-based thermal energy storage (TES) to shift peak-hour air conditioning (A/C) load to off-peak periods. The initial phase of the pilot project would involve identifying a customer, designing the system, and putting together a detailed cost estimate. The second phase would be purchasing and installing the equipment, followed by data collection to determine the effectiveness of the concept.

In August 2006, Idaho Power filed a license amendment application with FERC to expand the Shoshone Falls Project from 12.5 MW to 61.5 MW. The project currently has three generator/turbine units with nameplate capacities of 11.5 MW, 0.6 MW, and 0.4 MW. The expansion project involves replacing the two smaller units with a single 50-MW unit that will result in a net expansion of 49 MW. In July 2010, FERC issued a license amendment for the project allowing two years to begin construction and five years to complete the project. Idaho Power has received two extensions from FERC since the issuance of the license amendment. The latest extension, granted by FERC in May 2014, allows Idaho Power until July 2022 to complete the project.

Construction associated with renovations at the intake structure, the new scenic flow structure, and the replacement of the gated spillway at Shoshone Falls commenced in 2014 and is scheduled to be completed in December 2015. Idaho Power continues to analyze the costs and benefits of the generator/turbine expansion segment of the project.

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.