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Home My WebLink About20231215Service Quality Report 2023.pdf 1407 W. North Temple, Suite 330 Salt Lake City, UT 84116 December 15, 2023 VIA ELECTRONIC DELIVERY Commission Secretary Idaho Public Utilities Commission 11331 W. Chinden Blvd Building 8 Suite 201A Boise, ID 83714 RE: PAC-E-12-02 - Service Quality & Customer Guarantee Report for the period January 1 through June 30, 2023 Attention: Commission Secretary Rocky Mountain Power, a division of PacifiCorp, hereby provides a copy of the Service Quality & Customer Guarantee report covering January 1 through June 30, 2023. This report is provided pursuant to a merger commitment made during the PacifiCorp and ScottishPower1 merger and later affirmed by the Commission in Order No. 32583. The Company committed to implement a five-year Service Standards and Customer Guarantees program. The purposes behind these programs were to improve service to customers and to emphasize to employees that customer service is a top priority. Towards the end of the five-year merger commitment the Company filed an application2 with the Commission requesting authorization to extend these programs. Beginning with the June 15, 2023 Service Quality & Customer Guarantee report, PacifiCorp has added an Elevated Fire Risk (EFR) subcategory for SAIDI events to better track any outages that may occur while the Company is using EFR settings during weather fire conditions. When EFR settings are used, certain operational responses may also differ, which may result in more sustained outage events and longer outage duration. The added subcategory helps the Company and stakeholders better track how EFR settings may be affecting reliability. Informal inquiries may be directed to Mark Alder, Idaho Regulatory Manager at (801) 220-2313. Very truly yours, Joelle Steward Senior Vice President, Regulation and Customer & Community Solutions 1 Case No. PAC-E-99-01. 2 Case No. PAC-E-04-07. RECEIVED 2023 DECEMBER 15, 2023 11:52AM IDAHO PUBLIC UTILITIES COMMISSION IDAHO SERVICE QUALITY REVIEW January 1 – June 30, 2023 Report IDAHO Service Quality Review January – June 2023 Page 2 of 21 Table of Contents Executive Summary .................................................................................................................................... 3 1 Reliability Performance ....................................................................................................................... 4 1.1 System Average Interruption Duration Index (SAIDI) ..................................................................................................... 4 1.2 System Average Interruption Frequency Index (SAIFI) ................................................................................................... 6 1.3 Major and Significant Events .......................................................................................................................................... 6 1.4 Restore Service to 80% of Customers within 3 Hours .................................................................................................... 7 2 Reliability History ................................................................................................................................. 8 2.1 Idaho Reliability Historical Performance ......................................................................................................................... 8 2.2 Controllable, Non-Controllable and Underlying Performance Review ........................................................................... 8 2.3 Underlying Cause Analysis Table .................................................................................................................................. 11 2.4 Cause Category Analysis Charts .................................................................................................................................... 13 3 Reliability Improvement Process ....................................................................................................... 14 3.1 Transmission Investments ............................................................................................................................................ 14 4 Customer Response ........................................................................................................................... 16 4.1 Telephone Service and Response to Commission Complaints ..................................................................................... 16 4.2 Customer Guarantees Program Status ......................................................................................................................... 16 5 Service Standards/Program Summary ............................................................................................... 17 5.1 Service Standards Program ........................................................................................................................................... 17 5.1.1 Rocky Mountain Power Customer Guarantees ................................................................................................... 17 5.1.2 Rocky Mountain Power Performance Standards ................................................................................................ 17 5.2 Cause Code Analysis ...................................................................................................................................................... 18 5.3 Reliability Definitions .................................................................................................................................................... 19 IDAHO Service Quality Review January – June 2023 Page 3 of 21 Executive Summary Rocky Mountain Power developed its Customer Service Standards and Service Quality Measures in 1999. The Company developed the program by benchmarking its performance against relevant industry reliability and customer service standards. In some cases, Rocky Mountain Power has expanded upon these Standards. In other cases (largely where the industry has no established standard) Rocky Mountain Power developed its own metrics, targets, and reporting methods. The Standards guide and reaffirm the importance of customer service both external and internally. The Company distinguishes between non-controllable outages (e.g., lightning, vehicle collisions) and controllable outages (e.g., animal interference, equipment failure) and takes cost-effective steps to minimize both. As part of the Company’s Performance Standards Program, it annually evaluates individual electrical circuits to focus on those that have the most frequent interruptions. These are targeted for improvement and generally completed within two years. For the period January to June 2023, results of network performance as measured by System Average Interruption Duration Index (SAIDI) and System Average Interruption Frequency Index (SAIFI) in Idaho are favorable to the Company’s plan. The Company’s goal continues to be supplying safe, reliable power to Idaho. Rocky Mountain Power is dedicated to learning from our past service experiences and continuing to make improvements to our operations and customer service to ensure Idaho’s needs are met. Below is a summary of our midyear 2023 performance serving the customers of Idaho. IDAHO Service Quality Review January – June 2023 Page 4 of 21 1 Reliability Performance Rocky Mountain Power strives to deliver reliable service to its customers in Idaho. For the reporting period, the Company’s network performance was favorable as measured by System Average Interruption Duration Index (SAIDI) and System Average Interruption Frequency Index (SAIFI) in Idaho. Results for Idaho underlying performance can be seen in subsections 1.1 and 1.2 below. During the reporting period there were no major events and two significant event days. Details regarding these events are found in section 1.3. Section 1.4 shows Company outage response performance. Transmission outages continue to cause a significant impact to the customers in Idaho. These outages have a greater tendency to reach the established Major Event thresholds and make up most significant event days. 1.1 System Average Interruption Duration Index (SAIDI) Below is the Company’s underlying1 interruption duration performance through June 2023. IDAHO RELIABILITY PERFORMANCE FOR 2023 SAIDI (reporting period) (year-end) Controllable2 10.1 N/A Uncontrollable 37.0 N/A Underlying (Controllable + Uncontrollable) 47.1 130 Elevated Fire Risk (EFR)3 0 N/A Major Events 0 N/A Planned/Pre-Arranged 26.7 N/A Total Performance (Excluding Pre-Arranged) 47.1 130 (Including Pre-Arranged) 73.8 N/A 1 Underlying events include all sustained interruptions, whether of a controllable or non-controllable cause, exclusive of major events, elevated fire risk outages, prearranged (which can include short notice emergency prearranged outages), customer requested interruptions and forced outages mandated by public authority typically regarding safety in an emergency. 2 Controllable categories include Animals, Bird Mortality (non-protected and protected species), Bird Nest, Bird Suspected-No Mortality, Bad Order Equipment, Deterioration or Rotting, Faulty Install, Overload, and Trees – Trimmable. 3 As part of the Company’s wildfire mitigation programs, the Company may use protection coordination settings, referred to as “Elevated Fire Risk” (EFR) settings, that more substantially affected distribution system performance than standard settings. In 2021, the Company developed a method to estimate the reliability impacts of the device setting changes. EFR settings are applied when fire weather conditions, such as high winds, low fuel moisture, elevated temperature, low relative humidity, and volatile fuels, are greatest. When EFR settings are used, certain operational responses may also differ, which may result in more sustained outage events and longer outage duration. The value shown indicated the total SAIDI impact for outages that occur while circuits were on EFR settings. IDAHO Service Quality Review January – June 2023 Page 5 of 21 IDAHO Service Quality Review January – June 2023 Page 6 of 21 1.2 System Average Interruption Frequency Index (SAIFI) Below are the Company’s underlying interruption frequency performance results through June 2023. IDAHO Underlying SAIFI SAIFI (reporting period) (year-end) Underlying (major events excluded) 0.497 1.75 Total (major events included) 1.3 Major and Significant Events Major Event General Descriptions There were no major events during the reporting period met the Company’s Idaho major event threshold level5 for exclusion from underlying performance results. Significant Events Significant event days add substantially to year-on-year cumulative performance results; fewer significant event days generally result in better reliability for the reporting period, while more significant event days generally means poorer reliability results. During the reporting period two significant event days6 were recorded, which accounted for 13.06 SAIDI minutes, or about 28 percent of the reporting period’s underlying 47.1 SAIDI minutes. 4 Our yearly SAIFI Plan does not include major events. 5 A Major Event (ME) is defined as a 24-hour period where SAIDI exceeds a statistically derived threshold value (Reliability Standard IEEE 1366-2012) based on the 2.5 beta methodology. The values used for the reporting period are shown below: Effective Date Customer Count ME Threshold SAIDI ME Customer Minutes Lost 1/1-12/31/2023 86,783 12.954 1,124,197 6 On a trial basis, the Company established a variable of 1.75 times the standard deviation of its natural log SAIDI results. IDAHO Service Quality Review January – June 2023 Page 7 of 21 The Company has recognized that these significant days have caused a negative impact to performance and that they have been generally attributable to events within the transmission system. The Company has recognized transmission system reliability risks previously and continues on-going improvement plans. Significant Event Days Date Cause: General Description Underlying SAIDI Underlying SAIFI Underlying Underlying Loss of Transmission Line 5.43 0.062 11.5% 12.4% Loss of Transmission Line 7.63 0.032 16.2% 6.4% 1.4 Restore Service to 80% of Customers within 3 Hours Overall, the Company restored power outages due to loss of supply or damage to the distribution system within three hours to 91% of customers, achieving the goal of greater than 80%. RESTORATIONS WITHIN 3 HOURS Reporting Period Cumulative = 91% January February March April May June 88% 100% 93% 92% 95% 78% IDAHO Service Quality Review January – June 2023 Page 8 of 21 2 Reliability History Depicted below is the history of reliability in Idaho. In 2002, the Company implemented an automated outage management system which provided the background information from which to engineer solutions for improved performance. Since the development of this foundational information, the Company has been in a position to improve performance, both in underlying and in extreme weather conditions. These improvements have included: the application of geospatial tools to analyze reliability, development of web-based notifications when devices operate more than optimal, focus on operational responses via CAIDI metric analysis, and feeder hardening programs when specific feeders have significantly impacted reliability performance. 2.1 Idaho Reliability Historical Performance 2.2 Controllable, Non-Controllable and Underlying Performance Review In 2008, the Company introduced a further categorization of outage causes, which it subsequently used to develop improvement programs as developed by engineering resources. This categorization was titled Controllable Distribution Outages and recognized that certain types of outages can be cost-effectively avoided. As an example, animal-caused or equipment failure interruptions have a less random nature than lightning caused interruptions; other causes have also been determined and are specified in Section 2.3. Engineers can develop plans to mitigate against controllable distribution outages and provide better future reliability at the lowest possible cost. At that time, there was concern that the Company would lose focus on non-controllable IDAHO Service Quality Review January – June 2023 Page 9 of 21 outages.7 To provide insight into the response and history for those outages, the charts below distinguish amongst the outage groupings. The graphic history demonstrates controllable, non-controllable, and underlying performance on a rolling 365- day basis. Analysis of the trends displayed in the charts below shows a general improving trends for all charts. To also focus on non-controllable outages, the Company has continued to improve its resilience to extreme weather using such programs as its visual assurance program to evaluate facility condition. It also has undertaken efforts to establish impacts of loss of supply events on its customers and deliver appropriate improvements when identified. It uses its web-based notification tool for alerting field engineering and operational resources when devices have exceeded performance thresholds to react as quickly as possible to trends in declining reliability. These notifications are conducted regardless of whether the outage cause was controllable or not. 7 The Company shall provide, as an appendix to its Service Quality Review reports, information regarding non-controllable outages, including, when applicable, descriptions of efforts made by the Company to improve service quality and reliability for causes the Company has identified as not controllable. The Company shall provide a supplemental filing, within 90 days, consisting of a process for measuring performance and improvements for the non-controllable events. IDAHO Service Quality Review January – June 2023 Page 10 of 21 IDAHO Service Quality Review January – June 2023 Page 11 of 21 2.3 Underlying Cause Analysis Table The table and charts below show the total customer minutes lost by cause and the total sustained interruptions by cause. The Underlying cause analysis table excludes major events and includes prearranged outages (Customer Requested, Customer Notice Given, Construction, and Planned Notice Exempt line items) with subtotals for their inclusion, while the grand totals in the table exclude these prearranged outages so that grand totals align with reported SAIDI and SAIFI metrics for the period. 0 0.5 1 1.5 2 2.5 3 0 50 100 150 200 250 300 SA I F I ( E v e n t s ) SA I D I ( M i n u t e s ) Idaho 365-Day Rolling Non-Controllable History as Reported Stress Period SAIDI SAIFI Linear (SAIDI) IDAHO Service Quality Review January – June 2023 Page 12 of 21 Idaho Cause Analysis - Underlying 01/01/2023 - 06/30/2023 Direct Cause SAIDI SAIFI ANIMALS 28,413 294 40 0.33 0.003 BIRD MORTALITY (NON-PROTECTED SPECIES) 5,699 69 20 0.07 0.001 BIRD MORTALITY (PROTECTED SPECIES) (BMTS) 7,946 79 4 0.09 0.001 BIRD NEST (BMTS) 702 7 7 0.01 0.000 BIRD SUSPECTED, NO MORTALITY 53,314 909 35 0.61 0.011 CONTAMINATION 788 1 1 0.01 0.000 FIRE/SMOKE (NOT DUE TO FAULTS) 1,791 11 1 0.02 0.000 FLOODING 25 1 1 0.00 0.000 BAD ORDER EQUIPMENT 248,491 2,740 91 2.86 0.032 DETERIORATION OR ROTTING 454,833 3,709 248 5.24 0.043 NEARBY FAULT 138.017 1 1 0.00 0.000 OVERLOAD 5,436 346 4 0.06 0.004 POLE FIRE 37,183 128 7 0.43 0.002 DIG-IN (NON-PACIFICORP PERSONNEL) 19,476 314 6 0.22 0.004 OTHER INTERFERING OBJECT 3,469 15 7 0.04 0.000 OTHER UTILITY/CONTRACTOR 17,844 341 2 0.21 0.004 VEHICLE ACCIDENT 608,221 5,727 24 7.01 0.066 LOSS OF FEED FROM SUPPLIER 49,783 572 1 0.57 0.007 LOSS OF SUBSTATION 167,505 2,446 7 1.93 0.028 LOSS OF TRANSMISSION LINE 1,496,795 15,788 74 17.25 0.182 IMPROPER PROTECTIVE COORDINATION 2774.583 16 1 0.03 0.000 INCORRECT RECORDS 34.583 1 1 0.00 0.000 OTHER, KNOWN CAUSE 91,837 963 97 1.06 0.011 UNKNOWN 153,265 2,029 168 1.77 0.023 CONSTRUCTION 833 10 2 0.01 0.000 CUSTOMER NOTICE GIVEN* 1,760,103 8,572 106 20.28 0.099 CUSTOMER REQUESTED* 18,058 458 6 0.21 0.005 EMERGENCY DAMAGE REPAIR* 25,933 586 19 0.30 0.007 INTENTIONAL TO CLEAR TROUBLE 4,508 83 5 0.05 0.001 PLANNED NOTICE EXEMPT* 512,114 5,249 67 5.90 0.061 TREE - NON-PREVENTABLE 76,953 1,526 12 0.89 0.018 TREE - TRIMMABLE 73,246 512 2 0.84 0.006 FREEZING FOG & FROST 57,706 282 8 0.66 0.003 ICE 11,063 81 16 0.13 0.001 LIGHTNING 80,198 782 46 0.92 0.009 SNOW, SLEET AND BLIZZARD 83,715 582 38 0.96 0.007 WIND 245,507 2,752 100 2.83 0.032 * Note: Direct Cause categories marked with an asterisk (*) are prearranged or exempt from underlying values. IDAHO Service Quality Review January – June 2023 Page 13 of 21 2.4 Cause Category Analysis Charts The data presented in the charts and graphs below provides insights into the impact of different outage causes on service reliability. SAIDI and SAIFI metrics, representing average outage duration and frequency respectively, are used to quantify this impact. Some outages, though infrequent, lead to significant customer minutes lost, while others occur more often but with less overall impact. The pie charts further break down these metrics across all cause categories, excluding major and Planned events for clarity. IDAHO Service Quality Review January – June 2023 Page 14 of 21 3 Reliability Improvement Process Rocky Mountain Power is committed to delivering safe and reliable power. For years, the company has developed, monitored, and tracked reliability metrics in accordance with industry standards and regulatory requirements. Over time, improvements have been made to minimize the negative impact of power interruptions by reducing outage duration and frequency. To continue keeping its commitment to deliver safe and reliable power, Rocky Mountain Power develops a reliability plan annually to identify new projects and programs to continually improve system performance and resilience. Rocky Mountain Power’s reliability plan is a key program that is used to improve system reliability is the development of individual reliability work plans for areas of concern. This is a strategic approach based upon recent trends in performance as measured by customer minutes interrupted (CMI), from which SAIDI is derived. The decision to fund one performance improvement project over another is based on cost effectiveness as measured by the cost per avoided customer minute interruptions. Care is taken to ensure the cost effectiveness measure does not limit funding of improvement projects in areas of low customer density over more densely populated areas. An area of concern that has been identified are circuits that serve many customers. As a result, Rocky Mountain Power implemented a mainline sectionalizing guideline to reduce the number of customers exposed per feeder. The guide outlines recommendations for a maximum of 2,250 customers per feeder, which are to be further subdivided into protection zones of no more than 750 customers. A feeder analysis is performed annually to determine which feeders do not meet these recommendations, and then the identified feeders are prioritized based on the greatest amount of risk to reliability. 3.1 Transmission Investments Rocky Mountain Power has invested in improving the transmission reliability in Idaho over the past few years. The table below highlights significant projects that were completed in Idaho to improve reliability and address load growth. IDAHO Service Quality Review January – June 2023 Page 15 of 21 Description of CAPEX Project Description Montpelier Area Voltage Support 10/18/23 MVAr capacitor bank at St Charles Substation to resolve low voltage issues on the Montpelier, Idaho area 69 kV system after certain transmission ERICKSON JCT-WEBSTER 69KV LINE(REFRAME) 12/31/22 reframe 24 tangent structures "YS"&"PSSM" to TE201 on the Rigby-Rexburg 69 kV transmission line. Spiral dampers will also be installed as part of this Goshen #3 35/161 kV 400 MVA Transformer Install 11/15/22 Goshen substation located in southeast Idaho. This project is needed in order to resolve a potential overloading issue at the existing Goshen 345/161 kV transformers. Load in the Goshen area has continued to increase and as the load continues to grow, the risk of overloading the two existing Goshen 345/161 kV transformers increases. The 2016 Goshen area studies indicated that by 2021, loss of either one of the Goshen 345/161 kV transformers can overload the remaining Goshen 345/161 kV transformer above its emergency rating. The third transformer will be installed in 2021 Lava–McCammon 46kV 3.4-mile Reconductor 10/15/22 1/0-CU conductor between Lava and McCammon substations with new 397.5 ACSR “Ibis” conductor. It also includes the replacement of 26 single poles and four H-frame structures due to insufficient strength/height, and the installation of a 3/8” shield wire over the 3.4 miles. This completes the replacement of all original conductors on the 27.5-mile Grace–Lava– Rexburg Sub: Install 161 kV Source from Rigby 12/31/21 Rigby substation by converting an existing 69-kV line to 161-kV to create a 161-kV source at Rexburg substation through a new 161-69 kV transformer installation. The project also will include a new six breaker 69-kV ring bus at Rexburg substation that includes terminating two existing 69-kV lines and one new 69-kV line. Benefits of the project include establishing a new 161-kV source in the area, providing additional 69-kV capacity, improving 69-kV Malad Sub: Add Transmission Breakers and Relays 12/31/21 average of 12.7 trip and recloses per year from 2017 to 2019 that were attributed to contaminated insulator flashovers. Every trip and reclose results in a momentary outage for 2,856 customers served by Malad, Juniper, Snowville, and Holbrook substations. This project will expand Malad substation and install two new 138kV circuit breakers, relays, and communications. This will effectively split up the American Falls to Wheelon 138kV transmission line which will result in the ability to sectionalize the line always keeping the non-faulted section in-service. This ability to sectionalize the line will prevent customers from experiencing a momentary outage in Goshen-Sugarmill-Rigby 161kV Trans Line- T 12/15/21 kV transmission line from the Goshen to Sugarmill and Sugarmill to Rigby substations located in the southeast Idaho area. In addition, some of the existing 69 kV line will be rebuilt to 161 kV between Goshen and Sugarmill substation and the existing Ammon substation will be converted from 69 kV to 161 kV. This project is needed to increase reliability to both transmission and load service customers in the Goshen Idaho area. This project also addresses low voltage at Rigby and Sugarmill substations when under heavy Bonneville-Merrill-Hoopes 69kV ln +UB Reframe 4/1/21 line which is experiencing unacceptable outages. This will include replacing IDAHO Service Quality Review January – June 2023 Page 16 of 21 4 Customer Response 4.1 Telephone Service and Response to Commission Complaints The Company achieved most of its goals related to providing a timely response to customers concerns and commission complaints, except for the PS5 commitment, which was due to a staffing shortage. The Company is recruiting and training additional customer service representatives and expects the PS5 performance to continue to improve as these new employees are placed in their new roles. As of this report, in December 2023, the PS5 metric has increased to approximately 76% on a year-to-date basis. COMMITMENT GOAL PERFORMANCE PS5 Answer calls within 30 seconds 80% 75%8 PS6a Respond to commission complaints within 3 days 95% 100% PS6b 95% 100% PS6c Resolve commission complaints within 30 days 100% 100% 4.2 Customer Guarantees Program Status Overall Customer Guarantee performance remains above 99 percent, demonstrating the Company’s continued commitment to customer satisfaction. Major Events are excluded from the Customer Guarantees program. 8 As noted in recent reports, Rocky Mountain Power was unable to meet the specified goal due to staffing limitations, primarily caused by labor market dynamics during the COVID-19 pandemic. Despite these challenges, the company has been striving to enhance its performance and has demonstrated consistent improvement. In 2022, the performance rate was 63%. By the first quarter of 2023, this had increased to 70.1%. As of June 2023, the performance rate had further improved to 75%. Rocky Mountain Power continues to work diligently towards achieving its target. IDAHO Service Quality Review January – June 2023 Page 17 of 21 5 Service Standards/Program Summary9 5.1 Service Standards Program As referenced in Rule 25. 5.1.1 Rocky Mountain Power Customer Guarantees10 Customer Guarantee 1: Restoring Supply After an Outage The Company will restore supply after an outage within 24 hours of notification with certain exceptions as described in Rule 25. Customer Guarantee 2: Appointments The Company will keep mutually agreed upon appointments, which will be scheduled within a two-hour time window. Customer Guarantee 3: Switching on Power or applicant’s request, provided no construction is required, all government inspections are met and communicated to the Company and required payments are made. Disconnections for Estimates For New Supply applicant or customer within 15 working days after the initial Respond To Billing Inquiries initial contact. For those that require further investigation, the Company will investigate and respond to the Customer within 10 Resolving Meter Problems with a meter or conduct a meter test and report results to the Notification of Planned Interruptions notice prior to turning off power for planned interruptions 5.1.2 Rocky Mountain Power Performance Standards11 Network Performance Standard 1: Report System Average Interruption Duration Index (SAIDI) Controllable SAIDI and identify annual Underlying baseline performance targets for the reporting period. For actual performance variations from baseline, explanations of performance will be provided. The Company will also report rolling twelve-month performance for Controllable, Non- Report System Average Interruption Frequency Index (SAIFI) Controllable SAIFI and identify annual Underlying baseline performance targets for the reporting period. For actual performance variations from baseline, explanations of performance will be provided. The Company will also report rolling twelve-month performance for Controllable, Non- Improve Under-Performing Areas portions of circuits to improve performance by a forecast amount, using either its legacy worst performing circuit 9 On June 29, 2012, in Case No. PAC-E-12-02 and Order No. 32583, the Commission ordered that Rocky Mountain Power had delivered upon commitments it made in pursuant to the MidAmerican transaction in Case No. PAC-E-05-08 and Order No. 29998. The Commission also ordered the acceptance of modifications to the Service Standards Program proposed by Rocky Mountain Power. 10 See Rules for a complete description of terms and conditions for the Customer Guarantee Program. 11 Performance Standards 1, 2 and 4 are for underlying performance days and exclude those classified as Major Events. IDAHO Service Quality Review January – June 2023 Page 18 of 21 within five years after selection) or by application of its Supply Restoration supply or damage to the distribution system within three Telephone Service Level seconds. The Company will monitor customer satisfaction with the Company’s Customer Service Associates and quality of response received by customers through the Commission Complaint Response / Resolution disconnect Commission complaints within three working days and will b) respond to at least 95% of disconnect Commission complaints within four working hours and will c) resolve 95% of informal Commission complaints within 5.2 Cause Code Analysis The Company classifies outages based upon the cause categories and causes; causes are a further delineation within cause categories. It applies the definitions below to determine the outage cause categories. These categories and their causes can help support reliability analysis and improvement efforts. Direct Cause Category Category Definition & Example/Direct Cause Any problem nest that requires removal, relocation, trimming, etc.; any birds, squirrels, or other animals, whether or not remains found. • Animal (Animals) • Bird Nest • Bird Mortality (Non-protected species) • Bird or Nest • Bird Mortality (Protected species) (BMTS) • Bird Suspected, No Mortality Contamination or Airborne Deposit (i.e., salt, trona ash, other chemical dust, sawdust, etc.); corrosive environment; flooding due to rivers, broken water main, etc.; fire/smoke related to forest, brush or building fires (not including fires due to faults or lightning). • • • • • • • Equipment Failure Structural deterioration due to age (incl. pole rot); electrical load above limits; failure for no apparent reason; conditions resulting in a pole/cross arm fire due to reduced insulation qualities; equipment affected by fault on • • • • Interference utility dig-in; contact by outside utility, contractor or other third-party individual; vehicle accident, including • • • • • Loss of Supply • • • • • • Operational or commissioning error; relay setting error, including wrong fuse size, equipment by-passed; incorrect circuit • • • • IDAHO Service Quality Review January – June 2023 Page 19 of 21 • • • • • Other • • • Planned repairs after storm damage, car hit pole, etc.; construction work, regardless of whether notice is given; rolling • • • • • • • • Tree • • • Weather • • • • • • 5.3 Reliability Definitions This section will define the various terms used when referring to interruption types, performance metrics and the internal measures developed to meet its performance plans. Interruption Types Below are the definitions for interruption events. For further details, refer to IEEE 1366-2003/201212 Standard for Reliability Indices. Sustained Outage A sustained outage is defined as an outage greater than 5 minutes in duration. Momentary Outage Event A momentary outage event is defined as an outage equal to or less than 5 minutes in duration and comprises all operations of the device during the momentary duration; if a breaker goes to lockout (it is unable to clear the faulted condition after the equipment’s prescribed number of operations) the momentary operations are part of the ensuing sustained interruption. This sequence of events typically occurs when the system is trying to re- establish energy flow after a faulted condition and is associated with circuit breakers or other automatic reclosing devices. Rocky Mountain Power uses the locations where SCADA (Supervisory Control and Data Acquisition) exists and calculates consistent with IEEE 1366-2003/2012. Where no substation breaker SCADA exists, fault counts at substation breakers are to be used. Reliability Indices SAIDI SAIDI (system average interruption duration index) is an industry-defined term to define the average duration summed for all sustained outages a customer experiences in each period. It is calculated by summing all customer minutes lost for sustained outages (those exceeding 5 minutes) and dividing by all customers served within the study area. When not explicitly stated otherwise, this value can be assumed to be for a one-year period. Daily SAIDI To evaluate trends during a year and to establish Major Event Thresholds, a daily SAIDI value is often used as a measure. This concept is contained IEEE Standard 1366-2012. This is the day’s total customer minutes out of 12 IEEE 1366-2003 was adopted by the IEEE on December 23, 2003. It was subsequently modified in IEEE 1366-2012, but all definitions used in this document are consistent between these two versions. The definitions and methodology detailed therein are now industry standards. IDAHO Service Quality Review January – June 2023 Page 20 of 21 service divided by the static customer count for the year. It is the total average outage duration customers experienced for that given day. When these daily values are accumulated through the year, it yields the year’s SAIDI results. SAIFI SAIFI (system average interruption frequency index) is an industry-defined term that attempts to identify the frequency of all sustained outages that the average customer experiences during a given period. It is calculated by summing all customer interruptions for sustained outages (those exceeding 5 minutes in duration) and dividing by all customers served within the study area. CAIDI CAIDI (customer average interruption duration index) is an industry standard index that is the result of dividing the duration of the average customer’s sustained outages by frequency of outages for that average customer. While the Company did not originally specify this metric under the umbrella of the Performance Standards Program within the context of the Service Standards Commitments, it has since been determined to be valuable for reporting purposes. It is derived by dividing PS1 (SAIDI) by PS2 (SAIFI). MAIFIE MAIFIE (momentary average interruption event frequency index) is an industry standard index that quantifies the frequency of all momentary interruption events that the average customer experiences during a given timeframe. It is calculated by counting all momentary interruptions which occur within a 5-minute period, if the interruption event did not result in a device experiencing a sustained interruption. CEMI CEMI is an acronym for Customers Experiencing Multiple (Sustained and Momentary) Interruptions. This index depicts repetition of outages across the period being reported and can be an indicator of recent portions of the system that have experienced reliability challenges. This metric is used to evaluate customer-specific reliability. CPI99 CPI99 is an acronym for Circuit Performance Indicator, which uses key reliability metrics of the circuit to identify underperforming circuits. It excludes Major Event and Loss of Supply or Transmission outages. The variables and equation for calculating CPI are: CPI = Index * ((SAIDI * WF * NF) + (SAIFI * WF * NF) + (MAIFI * WF * NF) + (Lockouts * WF * NF)) Index: 10.645 SAIDI: Weighting Factor 0.30, Normalizing Factor 0.029 SAIFI: Weighting Factor 0.30, Normalizing Factor 2.439 MAIFI: Weighting Factor 0.20, Normalizing Factor 0.70 Lockouts: Weighting Factor 0.20, Normalizing Factor 2.00 Therefore, 10.645 * ((3-year SAIDI * 0.30 * 0.029) + (3-year SAIFI * 0.30 * 2.439) + (3-year MAIFI * 0.20 * 0.70) + (3-year breaker lockouts * 0.20 * 2.00)) = CPI Score CPI05 CPI05 is an acronym for Circuit Performance Indicator, which uses key reliability metrics of the circuit to identify underperforming circuits. Unlike CPI99 it includes Major Event and Loss of Supply or Transmission outages. The calculation of CPI05 uses the same weighting and normalizing factors as CPI99. RPI RPI is an acronym for Reliability Performance Indicator, which measures reliability performance on a specific segment of a circuit to identify underperforming circuit segments rather than measuring performance of the whole circuit. This is the Company’s refinement to its historic CPI, more granular. IDAHO Service Quality Review January – June 2023 Page 21 of 21 Performance Types & Commitments Rocky Mountain Power recognizes several categories of performance: major events and underlying performance. Underlying performance days may be significant event days. Outages recorded during any day may be classified as “controllable” events. Major Events A Major Event (ME) is defined as a 24-hour period where SAIDI exceeds a statistically derived threshold value (Reliability Standard IEEE 1366-2012) based on the 2.5 beta methodology. The values used for the reporting period and the prospective period are shown below. Effective Date Customer Count ME Threshold SAIDI ME Customer Minutes Lost 1/1-12/31/2023 86,783 12.954 1,124,197 Significant Events The Company has evaluated its year-to-year performance and as part of an industry weather normalization task force, sponsored by the IEEE Distribution Reliability Working Group, determined that when the Company recorded a day in excess of 1.75 beta (or 1.75 times the natural log standard deviation beyond the natural log daily average for the day’s SAIDI) that generally these days’ events are generally associated with weather events and serve as an indicator of a day which accrues substantial reliability metrics, adding to the cumulative reliability results for the period. As a result, the Company individually identifies these days so that year-on-year comparisons are informed by the quantity and their combined impact to the reporting period results. Underlying Events Within the industry, there has been a great need to develop methodologies to evaluate year-on-year performance. This has led to the development of methods for segregating outlier days, via the approaches described above. Those days which fall below the statistically derived threshold represent “underlying” performance and are valid. If any changes have occurred in outage reporting processes, those impacts need to be considered when making comparisons. Underlying events include all sustained interruptions, whether of a controllable or non-controllable cause, exclusive of major events, prearranged (which can include short notice emergency prearranged outages), customer requested interruptions and forced outages mandated by public authority typically regarding safety in an emergency. Controllable Distribution (CD) Events In 2008, the Company identified the benefit of separating its tracking of outage causes into those that can be classified as “controllable” (and thereby reduced through preventive work) from those that are “non- controllable” (and thus cannot be mitigated through engineering programs); they will generally be referred to in subsequent text as controllable distribution (CD). For example, outages caused by deteriorated equipment or animal interference are classified as controllable distribution since the Company can take preventive measures with a high probability to avoid future recurrences, while vehicle interference or weather events are largely out of the Company’s control and generally not avoidable through engineering programs. (It should be noted that Controllable Events is a subset of Underlying Events. The Cause Code Analysis section of this report contains two tables for Controllable Distribution and Non-controllable Distribution, which list the Company’s performance by direct cause under each classification.) At the time that the Company established the determination of controllable and non-controllable distribution it undertook significant root cause analysis of each cause type and its proper categorization (either controllable or non-controllable). Thus, when outages are completed and evaluated, and if the outage cause designation is improperly identified as non-controllable, then it would result in correction to the outage’s cause to preserve the association between controllable and non-controllable based on the outage cause code. The Company distinguishes the performance delivered using this differentiation for comparing year to date performance against underlying and total performance metrics.