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HomeMy WebLinkAboutSection II Electric.pdfIdaho Public Utilities Commission Page 22 ELECTRICAL POWER IN IDAHO Avista Utilities 334,848 residential customers/$0.0994 per kWh 42,154 commercial customers/$0.09651 1,328 industrial customers/$0.06115 Idaho Power Company 448,800 residential customers/$0.1032 per kWh 89,703 commercial customers/$0.0799 120 industrial customers/$0.0583 Rocky Mountain Power 63,824 residential customers/$0.1056 per kWh 9,505 commercial customers/$0.0895 622 industrial customers/$0.0645 The information below shows each regulated electric utility’s average number of customers per customer class and the average revenue per kilowatt-hour (kWh) for 2017. Idaho Public Utilities Commission Page 23 ELECTRIC CASES Atlanta Power investigation In February, the Commission initiated an investigation into Atlanta Power Company, a small electric utility that serves the unincorporated community of Atlanta in Elmore County. The investigation stems from a formal complaint filed against the utility by one of its approximately 75 customers. The complaint addressed several issues, including frequent and prolonged power outages, a lack of qualified personnel to operate and maintain facilities, and the company’s inaccessibility and failure to respond to complaints and issues. Hells Canyon relicensing In April, the Commission approved a settlement agreement allowing Idaho Power to recover expenses incurred in a decades-long effort to relicense its largest hydroelectric complex. The Hells Canyon Complex consists of the Brownlee, Oxbow and Hells Canyon dams and is capable of providing 1,167 megawatts of electricity, or about 30 percent of the company’s total generating capacity. The Commission’s order allows Idaho Power to recover approximately $216.5 million through customer rates at a later date. That is a decrease of almost $5 million from Idaho Power’s initial request and it covers expenses incurred since the relicensing effort began in 1991. While the Commission is charged with determining whether these costs can be recovered from customers, the licensing process itself falls under the purview of the Federal Energy Regulatory Commission. Though the relicensing effort remains under way, Idaho Power sought the prudency determination before the process was complete, and in advance of a general rate case, primarily because company representatives who have been working on the relicensing effort for decades are on the verge of retirement but also because a prudency review outside of a general rate case allowed Commission staff to focus solely on the “extensive data” associated with the costs incurred over nearly three decades. Demand side management – Avista In mid-November, Avista asked the Commission to determine that approximately $22.7 million it spent on energy efficiency programs in 2016-17 was prudently incurred. The utility said more than $16.8 million, or 74 percent of the expenses incurred, were provided to customers in direct incentives for measures enacted to save energy. Avista contends its DSM programs saved 80,372 megawatt-hours, significantly exceeding its targets. Independent evaluators have determined that the expenses were cost-effective, according to the company. The Commission’s prudency review of the programs is intended to ensure the programs’ benefits exceed their costs. In addition to reducing power supply expenses for all customers and eliminating or postponing the need to build new generation, these programs provide incentives to encourage participating customers to lower their power bills. Continued on page 24 Idaho Public Utilities Commission Page 24 ELECTRIC CASES, CONTINUED Demand side management – Idaho Power In September, the Commission determined that approximately $44 million spent by Idaho Power on efficiency programs in 2017 was prudently incurred. The goal of the Commission’s annual review of the utility’s “demand side management” (DSM) programs is to ensure that the programs are cost effective, meaning that customers would pay more for energy if the programs were not in place. If the Commission determines that expenses are not prudently incurred, the expenses are borne by shareholders rather than customers. The Commission’s decision did not impact rates, however; Idaho Power’s efficiency programs are recovered through the Energy Efficiency Rider, a 3.75-percent surcharge that is applied to customer energy usage, in addition to base rates and the Power Cost Adjustment mechanism. Idaho Power said its suite of DSM programs saved 191,471 megawatt hours in 2017. That is enough energy to power 17,000 average homes for a year, and represents a 12-percent increase over 2016 savings. The Commission’s prudency review of the programs is intended to ensure the programs’ benefits exceed their costs. In addition to reducing power supply expenses for all customers and eliminating or postponing the need to build new generation, these programs provide incentives to encourage participating customers to lower their power bills. Demand side management – Rocky Mountain Power Rocky Mountain Power has asked the Commission to determine that approximately $8.5 million it spent on energy efficiency and conservation programs in 2016-17 was prudently incurred. Commission approval would allow the company to recover these efficiency expenses through funds generated by an efficiency rider that is currently set at 2.7 percent of the monthly bill amount. Rocky Mountain said its efficiency and conservation programs saved 15,830 megawatt hours in 2017 and 19,450 megawatt hours in 2016. The Commission’s prudency review of the programs is intended to ensure the programs’ benefits exceed their costs. In addition to reducing power supply expenses for all customers and eliminating or postponing the need to build new generation, these programs provide incentives to encourage participating customers to lower their power bills. Rocky Mountain gets CPCN for wind, transmission projects In mid-July, the Commission approved a Certificate of Public Convenience and Necessity (CPCN) for Rocky Mountain Power to build four new wind projects and associated transmission facilities. Idaho state law requires a regulated utility to obtain a CPCN from the Commission before constructing certain facilities or infrastructure. Continued on page 25 Idaho Public Utilities Commission Page 25 ELECTRIC CASES, CONTINUED Rocky Mountain’s proposed projects have a generating capacity of 860 megawatts, at an estimated cost of $2 billion. The Commission’s order established a procedure for the utility to recover its investment in the projects and contained a number of conditions intended to protect ratepayers, including a cap on recoverable costs. Rocky Mountain Power contended that the transmission projects will alleviate congestion on its transmission system and improve its ability to manage the intermittent load generated by the new wind turbines. Key to the projects is their eligibility for federal production tax credits that are expected to total about $137 million over 30 years. To qualify for the tax credits, the turbines must be operational by Dec. 31, 2020. Criticism of the proposal focused on the fact that the projects’ impetus was financial, or tied to the federal tax credits rather than to a need for more energy to meet customer demand. Rocky Mountain Power said acquiring new wind generation is more cost effective than power purchases in meeting its resource needs due to the tax credits. The Commission agreed but set conditions: Rocky Mountain will bear the risks associated with any portion of the wind projects that does not qualify for the federal tax credits due to delays in construction, and a cost cap that limits the expenses passed on to customers to the company’s estimated project costs. Rocky Mountain Power provides electric service to approximately 75,400 customers in southeast Idaho. That is approximately 7 percent of its customer base across a service territory that includes Utah and Wyoming. Avista rates decline Avista’s rates for residential service decreased by 5.5 percent on Oct. 1 after the Commission approved changes to two rate adjustment mechanisms, the Fixed Cost Adjustment (FCA) and Power Cost Adjustment (PCA), and slightly lowered the rate credit provided through Bonneville Power Administration’s Residential Exchange Program. The biggest impact on rates came through a 5-percent reduction to the FCA. Designed to remove a utility’s disincentive to promote energy efficiency and conservation among customers, the FCA can be adjusted annually with Commission approval, via a surcharge when authorized expenses exceed revenue or a rebate when FCA revenue surpasses expenses. The FCA that took effect Oct. 1 is a rebate of 0.176 cents per kilowatt-hour. Avista attributed the change primarily to higher energy use among its customers in 2017, because of a colder-than-normal winter. The change to the PCA resulted in a 1-percent decrease to rates effective Oct. 1, for a rebate of 0.326 cents per kilowatt-hour used. It too can be modified each fall with Commission approval, to reflect differences in the costs included in customer rates and the actual costs that the utility incurred generating and purchasing the power needed to serve its customers over the previous 12 months. Continued on page 26 Idaho Public Utilities Commission Page 26 ELECTRIC CASES, CONTINUED The PCA is a true-up mechanism in that it allows the utility to recover costs when actual expenses exceed the amount included in rates and for a rebate when expenses are lower than PCA-related revenue. The third rate adjustment mechanism that took effect Oct. 1, the Residential and Small Farm Energy Rate Adjustment Credit, provides a share of the benefits of the Columbia River hydropower system to customers. The credit approved is 0.069 cents per kilowatt-hour, down from a credit of 0.078 cents per kilowatt-hour. The company said the credit for 2018 is smaller than the previous credit due to the fact that customer energy use was higher than projected in 2017, leading to an over-refunded balance. The BPA credit is the results of a decades-old agreement between Avista and the Bonnneville Power Administration, which markets and distributed the wholesale energy generated through a network of hydropower projects on the Columbia and Snake rivers. Idaho Power rates decline In June the Commission approved changes to two billing mechanisms that decreased the average residential bill by $4.89 per month. The Power Cost Adjustment (PCA) and Fixed Cost Adjustment (FCA) change annually on June 1 with Commission approval. The FCA is a cost-recovery mechanism that allows the utility to recover a Commission-authorized amount of fixed costs per customer. It is adjusted each spring based on changes in energy use among customers over the previous year. If the fixed costs recovered are less than the fixed costs authorized in the most recent rate case, customers see a surcharge on their bill. If the company collects more in fixed costs than is authorized by the Commission, customer receive a credit. The intent of the FCA is to remove the utility’s financial disincentive to invest in energy efficiency and conservation programs, or encourage customers to use energy more wisely, since those programs can lead to a decline in energy sales. The change to the FCA that took effect June 1 lowered rates by $19.4 million for customers in the residential and general service customer classes. That’s a decrease of 3.61 percent for residential customers and equates to a monthly savings of $3.60 for the typical residential customer. The PCA decreased rates by $22.6 million for all customers. As a result, rates declined by 1.29 percent or $1.29 per month for the typical residential customer. The PCA allows Idaho Power to adjust its rates up or down each year to reflect the actual power supply costs incurred over the previous year. Those costs can vary significantly based on several factors outside of the utility’s control, including market prices for power, transmission costs, revenue from selling surplus power and water conditions that affect hydropower generation, which accounted for almost 50 percent of Idaho Power’s energy portfolio in 2017. In requesting Commission approval to lower the PCA, the utility said the change was primarily due to better-than- expected water conditions, which helped boost hydro generation.