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Idaho Public Utilities Commission
June 1, 2012
Contact: Gene Fadness (208) 334-0339, 890-2712
Website:
http://www.puc.idaho.govwww.puc.idaho.gov
Seven Idaho Power rate adjustments result in slight increase
State regulators today adopted adjustments to Idaho Power Company rates in seven separate cases that overall represent about a 0.6 percent increase for all customer classes combined, but about a 0.3 percent decrease to the residential class effective today.
The largest of these adjustments is a 5.1 percent increase to the annual Power Cost Adjustment (PCA), but that is offset by a revenue sharing agreement that reduces the PCA to about 1.7 percent.
Still pending before the commission is an application by Idaho Power to increase its annual revenue by $60 million to pay for the $398 million Langley Gulch natural gas plant five miles south of New Plymouth. If that application is approved, residential rates will increase by 6.6 percent effective July 1. The average increase to all customer classes would be about 7.6 percent.
On June 1 of every year since 1993, Idaho Power is allowed to adjust its rates up or down to reflect its annual cost of providing electricity. Because about half of the company’s power generation comes from hydropower facilities, Idaho Power’s power supply expenses vary from year to year due to changes in Snake River streamflows and in wholesale market power prices.
In 2010, the PCA was a 4.8 percent decrease and in 2011, it was a 6.5 percent decrease. However, this year Idaho Power’s power supply expense is $70 million above what is now collected in the PCA. Idaho Power’s earnings are not impacted by the PCA. All the revenue collected in the PCA is kept in a deferred account, audited by the commission, and can be used only to pay down power supply expense.
This year’s water forecast is slightly better than normal hydro conditions for the April-July runoff period, so water is not a primary factor. About 95 percent of the $70 million in additional power supply expense is in new power purchases from wind farms under the provisions of the federal Public Utility Regulatory Policies Act, or PURPA. PURPA requires regulated utilities to buy energy from qualifying renewable energy facilities.
The $70 million power supply expense is reduced by $27 million as the result of revenue sharing agreements adopted in the last two Idaho Power rate cases.
As part of the 2010 rate case settlement, Idaho Power was allowed to accelerate tax benefits to bolster its earnings if the company agreed to share 50-50 with customers all revenue exceeding 10 percent Return on Equity (ROE). If earnings exceeded 10.5 percent, 75 percent of that portion above 10.5 percent is shared with customers through a reduction in pension expense.
In a separate case filed at about the same time as the PCA, (IPC-E-12-13) Idaho Power reported an ROE higher than 10.5 percent. The customer portion of the sharing amount is $33 million. Grossed up for taxes, the amount applied against the PCA is $27.1 million and the amount applied against pension expense that would otherwise be included in customer rates is $20.3 million. The result for the PCA is about a 3.2 percent reduction.
Up until the agreement allowing Idaho Power to accelerate up to $45 million of investment tax credits, Idaho Power had not been able to earn its authorized rate of return for the previous decade. Improved earnings are important to maintain Idaho Power’s ability to finance ongoing plant investments needed to serve customers. “The company’s increased financial stability benefits customers by enabling the company to delay rate cases and potentially lower interest costs. It is beneficial to customers and to Idaho Power if the company can enhance its ability to stabilize earnings in the near term, strengthening the company’s position in the financial markets and enabling it to reduce the cost of borrowing funds for operations or plant investment,” the commission said in its order approving the agreement, which continues through 2014.
Following is a summary of the other rate adjustments effective today.
Boardman balancing account, Case No. IPC-E-12-09, 0.18 percent increase
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 percent of the owner of the plant due to be closed in 2020.
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’s share of the annual change to base rates the company is requesting to recover is $1.58 million. The proposed increase varies among customer classes with the proposed residential increase at 0.18 percent. The commission removed about $60,000 in contingency fees, reducing the company’s overall request to $1.52 million.
The $1.52 million 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.
Depreciation rates, Case No. IPC-E-12-08, 0.16 percent decrease
Originally, Idaho Power sought a $2.78 million increase to base rates to account for an increase in depreciation rates for plant-in-service. The increase was based on updated net salvage percentages and service life estimates for all plant assets, with the exception of the Boardman coal plant and automated meters, which are handled in separate applications. However, parties to the case, including commission staff and Micron Technology Inc. disagreed on depreciation expense for some components. The parties agreed to settle on a $1.38 million depreciation expense decrease rather than a $2.78 million depreciation expense increase.
Mechanical metering depreciation, Case No. IPC-E-12-07, 1.25 percent decrease
Idaho Power applied to decrease base rates by $10.55 million due to the removal of accelerated depreciation expense associated with removal of mechanical meters.
The company recently completed a three-year installation of automated meters. Mechanical metering equipment was fully depreciated on May 31. As a result, annual revenue decreased by $10.5 million, which reduces rates by 1.22 percent.
Fixed cost adjustment, Case No. IPC-E-12-12, 0.28 percent increase
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 conservation results in power sales declining. Sometimes referred to as “decoupling,” the FCA decouples (separates) Idaho Power’s fixed costs from its energy sales, assuring the utility will be able to recover its fixed costs as established in the most recent rate case regardless of how much energy customers save. If the company under collects its fixed costs of serving customers, customers get a surcharge. Conversely, if the company over collects fixed costs, customers receive a credit. The commission capped the percentage increase that could be collected from residential and small-business customers at no more than 3 percent.
This year, Idaho Power under-collected $8.83 million in fixed costs from the residential class and $1.48 million from the small-business class. The commission determined to blend the amounts to prevent the small commercial customers from receiving 1.02 cents per kWh surcharge and residential customers 0.18 cents per kWh. Assessing commercial customers that large an increase would have exceeded the 3 percent cap. Blending the two customer classes, the increase is 0.28 percent for both classes. This equates to a new FCA rate of 0.2028 cents per kWh for residential customers and 0.2597 cents per kWh for small-business customers.
Transmission deferral, IPC-E-12-06, 0.08 percent increase
Idaho Power is allowed to recover $2 million over three years for lost transmission revenue associated with a federal transmission case. The adjustment increases base energy rates by .0052 cents per kWh.
The Federal Energy Regulatory Commission (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 Jim Bridger power plant in western Wyoming to each utilities’ respective service territories. Since the initial FERC order, Idaho Power petitioned for rehearing and did amend portions of the Legacy Agreements, but the utility lost on appeal.
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