Idaho Power seeks rate hikes and cuts from Idaho commission

The Idaho Public Utilities Commission is currently handling seven rate adjustment requests from Idaho Power, including one related to the 300-MW Langley Gulch gas plant that is scheduled to be online on or before July 1.

The commission noted in a March 30 statement that not included among these seven adjustments is the annual Power Cost Adjustment (PCA) which also becomes effective June 1 each year and could have a positive or negative impact on the 3.35% net increase now proposed. Idaho Power is expected to file its PCA application on or about April 15.

  • Idaho Power, a unit of IDACORP (NYSE:IDA), is seeking to increase its annual revenue by $60m to pay for the $398m Langley Gulch natural gas plant located five miles south of New Plymouth. According to the company’s figures, the average increase if approved will be 7.1% effective July 1. The 300-MW plant came in under the $427m commitment estimate provided when the commission granted Idaho Power a Certificate of Public Necessity and Convenience to construct the plant in 2009. The plant is scheduled to be online on or before July 1.
  • As part of its 2010 rate case settlement, Idaho Power agreed to share 50-50 with customers all revenue exceeding a 10% return. The agreement was later modified to state that if the rate of return exceeded 10.5%, then 75% of the company’s share of those earnings will be used to offset company pension expenses that would otherwise be included in customer rates. In this application, Idaho Power states the amount due customers is $27m. About $20.3m of that will be used to apply against the company’s pension balancing account that would otherwise be collected through rates. The result is about a 3.2% rate reduction. The commission will take comments through May 4.
  • Idaho Power is seeking authority to decrease base rates as the result of removing about $10.5m in accelerated depreciation expense associated with its recently installed automated metering equipment. The meters are now fully installed, covering roughly 99% of the company’s service territory. The metering equipment will be fully depreciated by May 31; therefore the company is seeking a June 1 effective date for a reduction in base rates of about 1.25%. The commission is taking comments on this application through April 10.
  • Idaho Power is seeking a $2.65m increase to base rates to account for an increase in depreciation rates for plant-in-service. The increase is based on updated net salvage percentages and service life estimates for all plant assets, with the exception of the co-owned Boardman coal plant and automated meters, which are being handled in separate applications. The proposed increase varies from 0.29% to 0.32%, with the proposed residential increase at 0.31%. Commission staff will conduct an informal workshop on April 5.
  • In February, the commission approved Idaho Power’s application to establish a balancing account related to the early closure of the Boardman coal plant in Oregon. Idaho Power is a 10% owner of the plant, which is due to be closed in 2020 under a clean-air agreement with regulators. The balancing account tracks, on a cumulative basis, the difference between revenues and expenses associated with the shutdown. It ensures customers pay only for actual expenditures. Idaho Power’s share of the annual change to base rates the company is requesting to recover is $1.58m. The proposed increase varies among customer classes from 0.17% to 0.2%, with the proposed residential increase at 0.18%. The $1.58m includes the return associated with Boardman capital investments net the accumulated depreciation forecasted through Boardman’s remaining life, the costs of accelerating the plant’s depreciation and the decommissioning costs associated with the shutdown. Commission staff will conduct an informal workshop on this application on April 5.
  • The FCA, implemented in 2007, allows Idaho Power to recover the fixed costs it loses when conservation programs result in lower power sales. Without a mechanism like the FCA, there is a financial disincentive for Idaho Power to promote energy efficiency and conservation because it loses revenue when power sales fall. The commission capped the percentage increase that could be collected from residential and small-business customers at no more than 3%. Idaho Power has under-collected $8.83m in fixed costs from the residential class and $1.48m from the small-business class. Building on what already exists in the FCA account, the company is proposing an increase of $1.16m from both the residential and small-business classes of 0.28% effective June 1. The commission is taking comments through April 10.
  • The company wants to amortize $2m over three years to recover lost transmission revenue associated with a federal transmission case. In that case, FERC found that Idaho Power had assessed transmission fees to PacifiCorp for transmission service on Idaho Power lines that were significantly lower than the Open Access Transmission Tariff (OATT) rates Idaho Power proposed to charge other customers for similar transmission service. The rate charged PacifiCorp was part of three “Legacy Agreements” the two utilities entered into during the 1960s regarding transmission service from the coal-fired, co-owned Jim Bridger power plant in Wyoming to each utilities’ respective service territories. Since the initial FERC order, Idaho Power amended portions of the Legacy Agreements and was not successful in its petition for rehearing. The commission is taking comment on this application through April 19.

Idaho Power readies natural gas supply for new plant

“The Langley Gulch natural gas-fired combined cycle power plant located in Idaho is currently under construction and is contracted to achieve commercial operation no later than November 1, 2012,” said IDACORP’s Feb. 22 annual Form 10-K report. “Based on the current project status, Idaho Power estimates that the plant will be in service by July 1, 2012.”

Idaho Power already owns and operates the Danskin and Bennett Mountain combustion turbines, and is constructing the Langley Gulch natural gas-fired combined-cycle power plant. Natural gas for all facilities is purchased based on system requirements and dispatch efficiency. The natural gas is supplied through Williams-Northwest Pipeline under Idaho Power’s 55,584 million British thermal units (MMBtu) per day long-term gas transportation service agreements. The agreements vary in contract length, with the latest termination date of May 2042, but with extensions at Idaho Power’s discretion, the Form 10-K noted.

In addition to the long-term gas transportation service agreements, Idaho Power has entered into a long-term storage service agreement with Northwest Pipeline for 131,453 MMBtu of total storage capacity at the Jackson Prairie Storage Project. As the project is developed, storage capacity will be phased into service and allocated to Idaho Power on a monthly basis. Idaho Power’s current storage allotment is about 89% of its eventual total, with its full allotment expected to be reached by July 2012. This firm storage contract expires in 2043. Natural gas will be purchased and stored with the intent of fulfilling needs as identified for seasonal peaks or to meet system requirements.

About 1.2 million MMBtu’s of natural gas has been hedged using financial instruments for future purchases for start-up testing of the Langley Gulch plant expected to take place between March and May. Along with this, about 2.9 million MMBtu of natural gas has been financially hedged for future purchases for the operational dispatch of Langley Gulch from July 2012 to January 2013. Idaho Power plans to manage the procurement of additional natural gas as necessary to meet system requirements and fueling strategies.

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.