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Home My WebLink About20230330Painter Direct_Exhibits.pdf BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER REQUESTING APPROVAL OF $32.5 MILLON ECAM DEFERRAL ) CASE NO. PAC-E-23-09 ) ) DIRECT TESTIMONY OF ) JACK PAINTER ROCKY MOUNTAIN POWER CASE NO. PAC-E-23-09 March 2023 RECEIVED 2023 March, 30 4:18PM IDAHO PUBLIC UTILITIES COMMISSION Painter, Di-1 Rocky Mountain Power Q. Please state your name, business address, and present position with PacifiCorp 1 d/b/a Rocky Mountain Power (“Rocky Mountain Power” or the “Company”). 2 A. My name is Jack Painter and my business address is 825 NE Multnomah Street, Suite 3 600, Portland, Oregon 97232. My title is Net Power Cost Specialist. 4 QUALIFICATIONS 5 Q. Please describe your education and professional experience. 6 A. I received a Bachelor of Arts degree in Business Administration with a Finance major 7 from Washington State University in 2007. I have been employed by PacifiCorp since 8 2008 and have held positions in the regulation and jurisdictional loads departments. I 9 joined the regulatory net power costs group in 2019 and assumed my current role as a 10 Net Power Cost Specialist in 2020. 11 Q. Have you testified in previous regulatory proceedings? 12 A. Yes. I have previously provided testimony to the public utility commissions in Idaho, 13 Utah, Wyoming, Oregon, Washington, and California. 14 PURPOSE OF TESTIMONY 15 Q. What is the purpose of your testimony in this proceeding? 16 A. My testimony presents and supports the Company’s calculation of the Energy Cost 17 Adjustment Mechanism (“ECAM”) balancing account for the 12-month period of 18 January 1, 2022 through December 31, 2022 (“Deferral Period”). More specifically, I 19 provide the following: 20 • A summary of the ECAM calculation, including changes made to comply with 21 Commission orders; 22 • Details supporting the addition of approximately $32.5 million to the deferral 23 Painter, Di-2 Rocky Mountain Power balance, including $30.5 million customers’ share of ECAM costs, a $1.4 1 million decrease in renewable energy production tax credits (“PTCs”), $634 2 thousand in reasonable energy price (“REP”) qualified facility (“QF”) costs, a 3 credit of $295 thousand for wind availability liquidated damages, a $131 4 thousand renewable energy credit (“REC”) revenue differential, and $327 5 thousand interest accrued; 6 • Discussion of the main differences between adjusted actual net power costs 7 (“Actual NPC”) and net power costs in rates (“Base NPC”); and, 8 • Discussion about the Company’s participation in the Western Energy Imbalance 9 Market (“WEIM”) with the California Independent System Operator 10 (“CAISO”) and the benefits from the WEIM that are passed through to 11 customers. 12 Q. What other witnesses present testimony for the ECAM and Tariff Schedule 94 in 13 this case? 14 A. Mr. Robert M. Meredith, Director, Pricing & Tariff Policy, provides testimony on the 15 proposed rates in Electric Service Schedule No. 94, Energy Cost Adjustment 16 (“Schedule 94”). 17 SUMMARY OF THE ECAM DEFERRAL CALCULATION 18 Q. Please briefly describe the Company’s ECAM authorized by the Commission. 19 A. The ECAM tracks deviations between Actual NPC and Base NPC. When there is a 20 difference between these two amounts, 90 percent of the difference is deferred for later 21 recovery or return to customers.1 In addition to tracking the difference between Actual 22 1 See Order No. 30904 in Case No. PAC-E-08-08 and Order No. 33440 in Case No. PAC-E-15-09. Painter, Di-3 Rocky Mountain Power and Base NPC, the ECAM also tracks other items including PTCs, the Reasonable 1 Energy Price QF adjustment, wind availability liquidated damages, and revenues from 2 the sale of RECs.2 The purpose for tracking these items is to true up base rates to 3 actuals. The balance that accumulates over a deferral period is then passed on to 4 customers as a rate surcharge or credit. Schedule 94, described in Mr. Meredith’s 5 testimony, appears as a separate line item on customers’ bills and either collects from 6 or credits to customers the balance of deferred costs. Schedule 94 is adjusted as needed 7 in the Company’s annual ECAM filings. 8 The Company is required to file an application with the Commission annually 9 by April 1st to request approval of the deferral amount and the new Schedule 94 rates 10 to become effective June 1. 11 Q. Are there any changes to the ECAM calculation? 12 A. Yes. The rates for Base NPC, PTCs, RECs, and the Load Change Adjustment Revenue 13 (“LCAR”) have been updated to reflect rates established in the Company’s last general 14 rate case (“GRC”) Case No. PAC-E-21-07, which became effective January 1, 2022.3 15 The wind integration costs for third party wind have been removed because 16 PacifiCorp’s Open Access Transmission Tariff (“OATT”) Schedule 3 and 3A rates 17 include intra-hour wind integration costs and offset Base rates in FERC Account 456. 18 Liquidated damages for wind availability have been included and are passed to 19 customers outside of the sharing band. Finally, the Resource Tracking Mechanism 20 2 See In the Matter of PacifiCorp DBA Rocky Mountain Power’s Application to Modify the Energy Cost Adjustment Mechanism and Increase Rates, Case No. PAC-E-15-09, Order No. 33440 at 5–6 (December 23, 2015). 3 In the Matter of Rocky Mountain Power’s Application for Authority to Increase its Rates and Charges in Idaho and Approval of Proposed Electric Service Schedules and Regulations, Case No. PAC-E-21-07, Order No. 35277 (December 30, 2021). Painter, Di-4 Rocky Mountain Power (“RTM”) and the Lake Side 2 Resource Adder have been eliminated as part of the 1 Company’s last GRC. 2 ECAM DEFERRAL CALCULATION 3 Q. Please describe the calculation of the ECAM deferral included in this filing. 4 A. Table 1 summarizes the total ECAM deferral and provides a breakdown of the 5 individual components of the ECAM. For a detailed monthly calculation of the ECAM 6 deferral, please refer to Exhibit No. 1. 7 Table 1 – 2022 ECAM Deferral 8 The first section of Table 1 summarizes the Idaho-allocated share of those items 9 for which Idaho customers and the Company share responsibility, including: NPC 10 differential, Emerging Issues Task Force (“EITF”) 04-6 adjustment, and the LCAR 11 costs. The second section calculates the 90 percent customers’ share of these items. 12 Finally, the last section adds the following items that are either refunded or collected in 13 full (i.e., 100 percent): PTCs, REP QF costs, wind availability liquidated damages, REC 14 Calendar Year 2022 ECAM Deferral NPC Differential 35,322,826$ EITF 04-6 Adjustment 190,656 LCAR (1,578,588) Total Deferral Before Sharing 33,934,894$ Sharing Band 90% Customer Reponsibility 30,541,405$ Production Tax Credits 1,388,020$ REP QF Adjustment 634,305 Wind Liquidated Damages (295,039) REC Deferral (130,679) Interest on Deferral 326,544 Annual Deferral (Jan - Dec 2022)32,464,556$ Painter, Di-5 Rocky Mountain Power revenues, and interest on the deferral. The total of these items represents the ECAM 1 deferral. 2 Q. Based on your calculations, what is the balance expected to be in the ECAM 3 deferral account as of June 1, 2023? 4 A. Table 2 provides a summary of the ECAM balancing account activity starting with the 5 December 31, 2021, ECAM deferral balance of $29.9 million approved in Case 6 No. PAC-E-22-05. By June 1, 2023, the projected balance in the ECAM deferral 7 account will be approximately $32.2 million. During the Deferral Period, 8 approximately $32.5 million is added to the balance from the annual deferral and 9 interest, which is offset by $20.5 million of ECAM revenue collections through the 10 Deferral Period, and an estimated collection of $9.7 million of Schedule 94 revenues, 11 net of interest, between January and May of 2023. 12 Table 2 - Balancing Account Activity 13 Q. Please describe the ECAM calculations in Exhibit No. 1. 14 A. The ECAM deferral is calculated monthly by comparing Idaho-allocated Actual NPC 15 to the Base NPC collected in rates, and then deferring the differences into an ECAM 16 balancing account. Exhibit No. 1 includes details of the ECAM calculation. 17 Additionally, I have also provided confidential work papers supporting this exhibit. 18 ECAM Deferral Balance Deferral Balance - Dec 31, 2021 29,925,543$ Annual Deferral (Jan - Dec 2022) 32,138,012 Interest 326,544 ECAM Revenue Collection - Schedule 94 (20,448,621) December 31, 2022 Balance For Collection 41,941,478$ Schedule 94 Collection - Jan - May 2023 (9,853,367)$ Interest 154,045 Expected Balance as of June 1, 2023 32,242,155$ Painter, Di-6 Rocky Mountain Power Q. How are the Base NPC and Actual NPC calculated? 1 A. Exhibit No. 1 provides details of the ECAM calculation. The monthly Base NPC 2 collected in rates, as set forth in Exhibit No. 1 line 6, is calculated by taking the dollar-3 per-megawatt-hour Base NPC rate multiplied by the actual Idaho retail sales. The 4 Actual Idaho NPC, as set forth in Exhibit No. 1 line 11, is calculated by dividing the 5 monthly total Company Actual NPC in the Deferral Period by the actual monthly 6 system megawatt-hours (“MWh”) in the Deferral Period. To calculate Actual Idaho 7 NPC, the total Company Actual NPC dollar-per-megawatt-hour basis is then multiplied 8 by Idaho actual monthly MWh. 9 Q. Please describe how the NPC deferral is calculated. 10 A. The deferral is calculated monthly by subtracting the Base NPC collected in rates from 11 the Actual Idaho NPC. For the Deferral Period, the NPC differential was $35.3 million 12 before applying the 90 / 10 percent sharing band. 13 Q. What costs are included in the NPC differential for deferral? 14 A. The NPC differential for deferral captures all components of NPC as defined in the 15 Company’s general rate case proceedings and modeled by the Company’s production 16 dispatch model, the Generation and Regulation Initiative Decision Tool (“GRID”). 17 Specifically, Base NPC and Actual NPC include amounts booked to the following 18 Federal Energy Regulatory Commission (“FERC”) accounts: 19 Account 447 – Sales for resale; excluding on-system wholesale sales and other 20 revenues that are not modeled in GRID 21 Painter, Di-7 Rocky Mountain Power Account 501 – Fuel, steam generation; excluding fuel handling, start-up fuel 1 (gas and diesel fuel, residual disposal), and other costs that are 2 not modeled in GRID 3 Account 503 – Steam from other sources 4 Account 547 – Fuel, other generation 5 Account 555 – Purchased power; excluding the Bonneville Power 6 Administration (“BPA”) residential exchange credit pass-7 through if applicable 8 Account 565 – Transmission of electricity by others 9 Q. Are adjustments made to the Actual NPC before comparing them to Base NPC? 10 A. Yes. The Company adjusts Actual NPC to reflect the ratemaking treatment of several 11 items, including: 12 • out of period accounting entries booked in the Deferral Period that relate to 13 operations before implementation of the ECAM on July 1, 2009; 14 • buy-through of economic curtailment by interruptible industrial customers; 15 • revenue from a contract related to the Leaning Juniper wind resource; 16 • costs for situs-assigned resources/programs in Oregon and Utah; 17 • coal inventory adjustments to reflect coal costs in the correct period; 18 • legal fees related to fines and citations included in the cost of coal; 19 • liquidated damages that occurred outside the Deferral Period (all liquidated 20 damage fees per a coal supply agreement are booked in accordance with 21 generally accepted accounting principles); 22 • wind availability liquidated damages; and 23 Painter, Di-8 Rocky Mountain Power • reasonable energy price adjustments to QFs. 1 Q. Why is the July 1, 2009, cutoff used to determine out of period entries? 2 A. Since the ECAM took effect, customers’ rates have been adjusted to recover essentially 3 all of the Company’s actual net power costs, excluding any differences due to the 90 / 4 10 percent sharing band. Consequently, any accounting entries made during the current 5 Deferral Period that relate to any operating period since the ECAM took effect should 6 be reflected in customer rates, whether they increase or decrease Actual NPC. However, 7 accounting entries related to operating periods before the inception of the ECAM 8 should not impact the ECAM deferral. 9 Q. In addition to comparing Actual NPC to Base NPC, what other components are 10 included in the ECAM? 11 A. The ECAM calculation includes six additional components: (i) an adjustment for 12 deferred costs associated with coal mine stripping activities recorded under the 13 Financial Accounting Standards Board (“FASB”) EITF 04-6; (ii) the LCAR 14 adjustment; (iii) a true-up of PTCs; (iv) Idaho allocated REP QF costs; (v) wind 15 availability liquidated damages; and (vi) a true-up of REC revenues as authorized in 16 Order No. 32196. 17 Q. How is the adjustment for accounting pronouncement EITF 04-6 included in the 18 ECAM? 19 A. Line 13 of Exhibit No. 1 calculates coal stripping costs, reflecting Idaho’s allocated 20 differences between the coal stripping costs incurred by the Company during 21 excavation, as recorded on the Company’s books pursuant to the guidance of the 22 accounting pronouncement EITF 04-6, and the amortization of the coal stripping costs 23 Painter, Di-9 Rocky Mountain Power as approved by the Commission in Case No. PAC-E-09-08, Order No. 30987. During 1 the Deferral Period, the total EITF 04-6 coal stripping deferral adjustment results in a 2 $191 thousand increase to the ECAM deferral balance, before the application of the 3 90 / 10 percent sharing band. 4 Q. Please describe the LCAR adjustment. 5 A. The calculation of the LCAR adjustment is a symmetrical adjustment for over- or 6 under-collection of the energy-related portion of the Company’s embedded revenue 7 requirement for production facilities, as specified in Case No. GNR-E-10-03, Order 8 No. 32206. This adjustment accounts for variances in Idaho load that cause the 9 Company to collect more or less of these production-related costs. The LCAR rate of 10 $8.74 per MWh is used for the Deferral Period. 11 Q. How is the LCAR adjustment calculated and what impact does it have on the 12 Deferral Period? 13 A. The LCAR adjustment assumes that the actual production-related costs of the LCAR 14 are equivalent to the base amount on Exhibit No. 1 line 14. The actual production-15 related costs are then compared to the LCAR revenue collection in rates, calculated by 16 multiplying the LCAR rate by the actual Idaho retail sales on Exhibit No. 1 line 17. 17 The LCAR adjustment, which is shown on line 18 of Exhibit No. 1, is the difference 18 between the actual production-related costs and the LCAR revenue. This adjustment 19 results in a $1.6 million decrease to the ECAM deferral balance before application of 20 the 90 / 10 percent sharing band. 21 Painter, Di-10 Rocky Mountain Power Q. Please explain the sharing band ratio between the Company and customers in the 1 ECAM. 2 A. The ECAM includes a sharing band with a symmetrical sharing ratio in which 3 customers either pay or receive 90 percent of the ECAM deferral balance, and the 4 Company is responsible for the remaining 10 percent. Line 20 of Exhibit No. 1 5 represents the customers’ 90 percent share of the monthly deferral shown on line 19. 6 For the Deferral Period, the customers’ share of the deferred balance is $30.5 million. 7 The remaining balance of $3.4 million associated with the Company’s ten percent share 8 is not included in the deferral balance as it is not recoverable from customers. 9 Q. What is the amount of the PTC true-up in the current filing? 10 A. The PTC Deferral, on line 25 of Exhibit No. 1, is calculated by comparing the actual 11 Idaho-allocated PTC to the PTC credit customers receive through base rates. The PTC 12 credit in base rates is calculated by multiplying the approved PTC rate of $4.16/MWh 13 by Idaho retail sales. The difference results in a $1.4 million increase to the ECAM 14 deferral. 15 Q. Please explain the REP QF Adjustment. 16 A. As set forth in the 2020 Inter-Jurisdictional Allocation Protocol (“2020 Protocol”): “For 17 the Interim Period, the energy output of New QF PPAs will be dynamically allocated 18 per this agreement using the SG Factor, priced at a forecasted reasonable energy price 19 defined below, and any cost of a New QF PPA above the forecasted reasonable energy 20 price will be situs assigned to and allocated to the State of Origin.”4 The Idaho situs-21 assigned cost, on line 26 of Exhibit No. 1, is $634 thousand. 22 4 In the Matter of the Application for Approval of the 2020 PacifiCorp-Interjurisdictional Allocation Protocol, Case No. PAC-E-19-20, Order No. 34640 at § 4.4.2.1, 31 (April 22, 2020). Painter, Di-11 Rocky Mountain Power Q. Please explain the wind availability liquidated damages credit. 1 A. Order No. 33954 in Case No. PAC-E-17-06 provides that “the Stipulation requires the 2 Company to pass on to ratepayers all liquidated damages it receives from equipment 3 suppliers in case the repowered equipment does not meet specified availability, 4 performance, or installation schedule requirements.” The Company first removes the 5 wind availability liquidated damages from total-Company NPC and then allocates them 6 to customers using the System Generation (“SG”) allocation factor outside of the 90 /10 7 percent sharing band. The wind availability liquidated damages credited to customers 8 in the ECAM is $295 thousand, as shown on line 27 of Exhibit No. 1. 9 Q. What is the amount of REC revenue adjustment in the current filing? 10 A. The REC revenue adjustment shown on line 32 of Exhibit No. 1 is calculated by 11 comparing the actual Idaho-allocated REC revenue with the REC revenue credit 12 customers receive through base rates. The REC revenue credit in base rates is calculated 13 by multiplying the approved REC revenue rate of $0.07/MWh by Idaho retail sales. 14 The resulting difference is a $131 thousand decrease to the ECAM deferral. 15 Q. What is the total ECAM deferred balance calculated in Exhibit No. 1? 16 A. The total ECAM deferred balance as of December 31, 2022, is $32.1 million, shown 17 on line 33 of Exhibit No. 1, plus $327 thousand of interest on line 42, for a total deferral 18 of $32.5 million. 19 Q. Does the calculation of the ECAM deferral in this application comply with the 20 parameters of the Idaho ECAM as approved by the Commission? 21 A. Yes, therefore the Company recommends that the Commission approve the ECAM 22 application for recovery of the $32.5 million in prudently incurred ECAM costs. 23 Painter, Di-12 Rocky Mountain Power DIFFERENCES IN NPC 1 Q. On a total-Company basis, what was the difference between Actual NPC and Base 2 NPC for the Deferral Period? 3 A. On a total-Company basis, Actual NPC for the Deferral Period amounted to $2.018 4 billion, exceeding Base NPC for the Deferral Period by $650 million. Table 3 provides 5 a high-level summary of the difference between Base NPC and Actual NPC by category 6 on a total-Company basis. 7 Table 3 - Net Power Cost Reconciliation ($ millions) 8 Q. Please describe the Base NPC the Company used to calculate the NPC component 9 of the ECAM deferral. 10 A. The Base NPC were set in Case No. PAC-E-21-07 and became effective 11 January 1, 2022. Base NPC used the 12-month test period of January 2021 through 12 December 2021 and set total-Company Base NPC at $1.368 billion. 13 Q. Please describe some of the weather events that impacted NPC. 14 A. Similar to 2021, the year 2022 was also marked by several extreme and unforeseeable 15 weather events that has a collective impact on Actual NPC during the year. Multiple 16 TOTAL Base NPC 1,368$ Increase/(Decrease) to NPC: Wholesale Sales Revenue 178 Purchased Power Expense 98 Coal Fuel Expense (19) Natural Gas Expense 382 Wheeling and Other Expense 11 Total Increase/(Decrease)650$ Adjusted Actual NPC 2,018$ Painter, Di-13 Rocky Mountain Power heat waves across the Company’s service territories throughout July, August, and 1 September had a significant effect on market prices, ultimately leading to an increase 2 in NPC. Cumulatively, the NPC differential for those months amounted to $16.5 3 million, which is almost half of the entire $35.3 million variance on an Idaho-allocated 4 basis. 5 Additionally, ongoing drought in the West, which began in the summer of 2020, 6 continued to impact Actual NPC because it reduced the availability of the Company’s 7 hydro resources. In 2022, actual generation from hydro resources were 1,505,231 8 MWhs, which was 34 percent lower than forecasted generation and needed to be 9 replaced to meet customer demand either through system dispatch of other resources, 10 reducing market sales, increasing market purchases, or any combination of these 11 options. The estimated impact on total-Company NPC in 2022 due to decreased hydro 12 MWhs due to drought is $151 million. 13 Finally, in December 2022 a historic winter cyclone event occurred across the 14 majority of the United States, which impacted both market prices and natural gas prices, 15 along with an increase in demand. Natural gas prices across the Company’s delivery 16 points drastically increased. At the Opal natural gas trading hub, the average market 17 prices were 424 percent higher in December 2022 as compared to December 2021, 18 while market prices at the Mid-Columbia and Four-Corners trading hubs were, on 19 average, 406 percent higher across all load hours. The NPC differential in December 20 alone is $6.7 million, or 19 percent, of the total Idaho-allocated NPC variance. 21 Q. How has the conflict in Ukraine impacted regional natural gas fuel prices? 22 A. The ongoing conflict in Ukraine has resulted in decreased availability of natural gas in 23 Painter, Di-14 Rocky Mountain Power Europe, which was previously sourced from Russian imports. With decreased European 1 supply, the associated European demand has turned to U.S. domestic supply to fill the 2 gap. This has resulted in increased competition over domestic supply, which has driven 3 regional natural gas fuel prices upwards due to domestic production being unable to 4 keep pace with the increased demand. This increase in natural gas fuel prices 5 correspondingly increases regional natural gas market prices and regional power 6 market prices, in that order. It is difficult to predict (or forecast) how long, and in what 7 direction, these factors will continue to impact regional prices. 8 Q. Please describe the primary differences between Actual NPC and Base NPC. 9 A. From an accounting perspective, and as shown in Table 3, Actual NPC were higher than 10 Base NPC due to a $178 million reduction in wholesale sales, a $98 million increase in 11 purchased power expense, a $382 million increase in natural gas expense, and a $11 12 million increase in wheeling and other expenses. These items were partially offset by a 13 $19 million reduction in coal fuel expense. 14 Q. Please explain the changes in wholesale sales revenue. 15 A. Wholesale sales revenue declined relative to Base NPC due to higher market prices and 16 a reduction in the wholesale sales volume of market transactions (represented in GRID 17 as short-term firm and system balancing sales). Of the $178 million decrease to 18 wholesale sales, revenue from market transactions represents the largest change to Base 19 NPC. Market transactions are $209 million lower than Base NPC, specifically due to 20 the higher market prices and lower volume of market sales transactions mentioned 21 above. The average price of actual market sales transactions was $22.65/MWh, which 22 Painter, Di-15 Rocky Mountain Power is 52 percent higher than the average price in Base NPC. Actual wholesale market 1 volumes were 6,722 gigawatt-hours (“GWh”), or 64 percent, lower than the Base NPC. 2 Q. Please explain the changes in purchased power expense. 3 A. The expenses from market transactions (represented in GRID as short-term firm and 4 system balancing purchases) increased by $412 million compared to Base NPC, 5 making it the most significant driver. Actual market purchases were 1,039 GWh (13 6 percent) lower than Base NPC, but the average price of actual market purchases 7 transactions was $65.03/MWh (182 percent) higher than Base NPC. The biggest impact 8 to market transaction prices was tied to several heat waves throughout July, August, 9 and September, further compounded by ongoing drought dating back to the summer of 10 2020. 11 During the summer 2022 heat waves, the Mid-Columbia market hub saw an 12 average increase in heavy load hour market prices of 103 percent in August and 13 September as compared to the same timeframe in 2021. This is significant considering 14 2021 also experienced an extreme heat dome and drought. The Four Corners market 15 hub saw an average increase in heavy load hour market prices of 151 percent for the 16 same period. 17 Q. Please explain the changes in wheeling expenses. 18 A. The increase in wheeling expenses relative to Base NPC was primarily due to an 19 increase in short-term firm wheeling expense of $13.5 million. 20 Q. Please explain the changes in coal fuel expense. 21 A. Coal fuel expense decreased because coal generation volume decreased 1,484 GWh (5 22 percent) compared to Base NPC. Although the average cost of coal generation 23 Painter, Di-16 Rocky Mountain Power increased from $20.08/MWh in Base NPC to $20.47/MWh in the Deferral Period, the 1 lower generation volume results in an overall decrease of $19 million in coal fuel 2 expense. 3 Q. Please explain the changes in natural gas fuel expense. 4 A. The total natural gas fuel expense in Actual NPC increased by $382 million compared 5 to Base NPC. This was mainly due to an increase in average cost of natural gas 6 generation from $26.95/MWh in Base NPC to $44.61/MWh in the Deferral Period 7 caused by conflict in Ukraine and a historic winter weather event as discussed above. 8 In addition, there was an increase in gas generation volumes of 5,198 GWh (61 9 percent). 10 IMPACT OF PARTICIPATING IN THE WEIM 11 Q. Are the actual benefits from participating in the WEIM with CAISO included in 12 the ECAM deferral? 13 A. Yes. Participation in the WEIM provides benefits to customers in the form of reduced 14 Actual NPC. The WEIM benefits are embedded in Actual NPC through lower fuel and 15 purchased power costs. According to CAISO’s WEIM benefits report, PacifiCorp has 16 received $200 million in benefits in 2022 and $591.4 million since the inception of the 17 WEIM. 18 Q. Please summarize your testimony. 19 A. The ECAM deferral of $32.5 million, including interest, for the Deferral Period, was 20 accurately calculated in compliance with previous Commission orders. Therefore, I 21 respectfully request that the Commission approve this application as filed with rates 22 effective June 1, 2023. 23 Painter, Di-17 Rocky Mountain Power Q. Does this conclude your direct testimony? 1 A. Yes. 2 Case No. PAC-E-23-09 Exhibit No. 1 Witness: Jack Painter BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION ROCKY MOUNTAIN POWER ____________________________________________ Exhibit Accompanying Direct Testimony of Jack Painter March 2023 Idaho Energy Cost Adjustment Mechanism Deferr January 1, 2022 - December 31, 202 LinNo. CY 20211 ID Base NPC Embedded in Rates ($PAC-E-21-07 86,534,56$ 2 nnual Idaho Base Load @ meter (MWh PAC-E-21-07 3,526,353 NPC Rate Embedded in Base Rates ($/MWh Line 1 / Line 24.54$ Jan-22 Feb-22 Mar-22 Apr-22 May-22 Jun-22 Jul-22 Aug-22 Sep-22 Oct-22 Nov-224 NPC Rate Embedded in Base Rates ($/MWh Line 24.54$ 24.54$ 24.54$ 24.54$ 24.54$ 24.54$ 24.54$ 24.54$ 24.54$ 24.54$ 24.54$ 5 ID Actual Sales @ Meter (MWh 298,043 243,523 271,234 259,804 311,132 391,286 494,237 350,269 297,140 251,618 238,833 6 ID NPC Collected in Rates ($Line 4 x Line 7,313,771$ 5,975,88$ 6,655,89$ 6,375,41$ 7,634,96$ 9,601,91$ 12,128,26$ 8,595,38$ 7,291,62$ 6,174,53$ 5,860,811$ 7 Total Company Adjusted Actual NPC ($djusted Actual NP 148,270,35$ 126,512,75$ 121,891,77$ 131,742,131$ 138,364,69$ 133,568,84$ 227,031,38$ 216,086,211$ 192,844,56$ 138,951,54$ 175,269,84$ 8 Total Company Load @ Input (MWh 5,391,99 4,739,80 4,840,50 4,575,97 4,647,51 4,993,20 6,116,032 5,796,65 4,935,652 4,610,941 5,039,73 9 ctual NPC ($/MWh Line 7 / Line 27.50$ 26.69$ 25.18$ 28.79$ 29.77$ 26.75$ 37.12$ 37.28$ 39.07$ 30.14$ 34.78$ 10 ID Actual Load @ Input (MWh 309,600 255,102 273,360 267,595 342,454 415,263 521,018 352,422 307,012 270,190 242,32911ctual ID NP Line 9 x Line 1 8,513,452$ 6,809,07$ 6,883,63$ 7,704,05$ 10,195,46$ 11,108,32$ 19,340,56$ 13,137,52$ 11,995,48$ 8,142,22$ 8,427,60$ 12 NPC Differential Line 11 - Line 1,199,681$ 833,190$ 227,741$ 1,328,642$ 2,560,49$ 1,506,41$ 7,212,291$ 4,542,140$ 4,703,85$ 1,967,68$ 2,566,78$ EITF 04-6 Adjustmen 13 Idaho Allocated EITF 04-6 Deferral Adjustment ($(35,206)$ 124$ 23,090$ 43,918$ (65,172)$ (89,614)$ 79,342$ 124,80$ 7,959$ 87,13$ 21,54$ LCA 14 ctual Idaho Jurisdictional ECPC minus NPC (Assume Actual = PAC-E-21-07 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 15 LCAR Rate @ Meter ($/MWh PAC-E-21-07 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 16 ID Actual Sales @ Meter (MWh Line 298,043 243,523 271,234 259,804 311,132 391,286 494,237 350,269 297,140 251,618 238,833 17 LCAR Revenue Collected through Base Rates (Line 15 x Line 1 2,604,76$ 2,128,28$ 2,370,46$ 2,270,57$ 2,719,16$ 3,419,681$ 4,319,43$ 3,061,20$ 2,596,88$ 2,199,03$ 2,087,302$ 18 LCAR Adjustmen Line 14 - Line 1 (36,525)$ 439,957$ 197,77$ 297,66$ (150,918$ (851,438$ (1,751,188$ (492,966$ (28,638)$ 369,208$ 480,940$ ECAM Deferral19 Total ECAM Deferral (NPC Deferral, EITF 04-6 Adjustment, LCASum of Lines: 12, 13, 1 1,127,95 1,273,271 448,605 1,670,22 2,344,40 565,360 5,540,44 4,173,97 4,683,17 2,424,031 3,069,27 20 Total ECAM Deferral after 90% Sharin Line 19 x 90 1,015,15$ 1,145,94$ 403,74$ 1,503,20$ 2,109,96$ 508,82$ 4,986,401$ 3,756,581$ 4,214,85$ 2,181,62$ 2,762,34$ Production Tax Credits (PTCs21 ID Allocated PTCs in Rates ($/MWh PAC-E-21-07 (4.16$ (4.16$ (4.16$ (4.16$ (4.16$ (4.16$ (4.16$ (4.16$ (4.16$ (4.16$ (4.16$ 22 ID Actual Sales @ Meter (MWh Line 298,043 243,523 271,234 259,804 311,132 391,286 494,237 350,269 297,140 251,618 238,833 23 ID PTCs in Rates ($Line 21 x Line 2 (1,241,025$ (1,014,008$ (1,129,395$ (1,081,802$ (1,295,527$ (1,629,285$ (2,057,965$ (1,458,494$ (1,237,267$ (1,047,716$ (994,482$ 24 ID Allocated Actual PTCs ($(1,643,681 (1,590,954 (1,394,353 (1,439,211 (1,211,430 (876,345 (690,035 (628,766 (724,878 (921,948 (1,220,451 25 ID PTCs Deferral ($Line 24 - Line 2 (402,656$ (576,945$ (264,958$ (357,409$ 84,096$ 752,941$ 1,367,930$ 829,728$ 512,390$ 125,769$ (225,969$ Situs Assigned REP QF Adjustmen26 ID REP QF Adjustment ($3,642$ 6,52$ 5,277$ 42,967$ 78,488$ 127,253$ 68,56$ 56,281$ 37,079$ 78,72$ 44,193$ Wind Liquidated Damage27 ID Allocated Wind Liquidated Damages ($(52,304)$ $ $ $ $ $ $ $ $ $ (239,912$ Renewable Energy Credits (REC) Revenu28 ID REC Revenue in Rates ($/MWh PAC-E-21-07 (0.07$ (0.07$ (0.07$ (0.07$ (0.07$ (0.07$ (0.07$ (0.07$ (0.07$ (0.07$ (0.07$ 29 ID Actual Sales @ Meter (MWh Line 298,043 243,523 271,234 259,804 311,132 391,286 494,237 350,269 297,140 251,618 238,833 30 ID REC Revenue in Rates ($Line 28 x Line 2 (20,401$ (16,669$ (18,566$ (17,784$ (21,297$ (26,784$ (33,831$ (23,976$ (20,339$ (17,223$ (16,348$ 31 ID Allocated Actual REC Revenue ($(33,363 (15,420 (103,577 (98,901 (16,738 (29,836 (21,885 (3,551 16,899 (2,231 (2,696 32 REC Revenue Adjustment ($Line 31 - Line 3 (12,962)$ 1,249$ (85,011)$ (81,117)$ 4,560$ (3,053)$ 11,946$ 20,42$ 37,239$ 14,992$ 13,653$ 33 Total Deferral Sum of Lines 20, 25, 26, 27, 3 550,87$ 576,772$ 59,053$ 1,107,64$ 2,277,10$ 1,385,96$ 6,434,841$ 4,663,01$ 4,801,56$ 2,401,11$ 2,354,312$ 34 Interest Rat Order No. 3486 1.00%1.00%1.00%1.00%1.00%1.00%1.00%1.00%1.00%1.00%1.00% ECAM Balancing Account ($35 Beginning Balanc 29,925,54$ 29,605,861$ 28,862,30$ 28,422,82$ 28,674,96$ 30,048,80$ 29,912,72$ 32,244,61$ 34,870,97$ 37,291,82$ 37,836,661$ 36 ECAM Deferral After Sharin Line 2 1,015,15 1,145,94 403,744 1,503,20 2,109,96 508,824 4,986,401 3,756,581 4,214,85 2,181,62 2,762,34 37 PTCs Deferral Line 2 (402,656 (576,945 (264,958 (357,409 84,096 752,941 1,367,93 829,728 512,390 125,769 (225,969 38 REP Situs Adjustmen Line 2 3,642 6,524 5,277 42,967 78,488 127,253 68,564 56,281 37,079 78,724 44,193 39 Wind Liquidated Damage Line 2 (52,304 - - - - - - - - - (239,912 40 REC Revenue Adjustmen Line 3 (12,962 1,249 (85,011 (81,117 4,560 (3,053 11,946 20,425 37,239 14,992 13,653 41 Less: Monthly ECAM Rider Revenues allocated to ECA (895,351 (1,344,678 (522,392 (879,287 (927,727 (1,547,017 (4,128,846 (2,064,606 (2,410,769 (1,887,566 (1,911,839 42 Interes 24,794 24,352 23,859 23,781 24,458 24,974 25,888 27,953 30,055 31,290 31,715 43 Total ECAM Deferral Balance ($)29,605,861$ 28,862,307$ 28,422,828$ 28,674,966$ 30,048,805$ 29,912,727$ 32,244,610$ 34,870,972$ 37,291,823$ 37,836,661$ 38,310,848$ Rocky Mountain Power Exhibit No. 1 Page 1 of 2 Case No. PAC-E-23-09 Witness: Jack Painter Idaho Energy Cost Adjustment Mechanism Deferr January 1, 2022 - December 31, 202 LinNo. 1 ID Base NPC Embedded in Rates ($PAC-E-21-07 2 nnual Idaho Base Load @ meter (MWh PAC-E-21-073 NPC Rate Embedded in Base Rates ($/MWh Line 1 / Line 4 NPC Rate Embedded in Base Rates ($/MWh Line 5 ID Actual Sales @ Meter (MWh 6 ID NPC Collected in Rates ($Line 4 x Line 7 Total Company Adjusted Actual NPC ($djusted Actual NP 8 Total Company Load @ Input (MWh9ctual NPC ($/MWh Line 7 / Line 10 ID Actual Load @ Input (MWh11ctual ID NP Line 9 x Line 1 12 NPC Differential Line 11 - Line EITF 04-6 Adjustmen 13 Idaho Allocated EITF 04-6 Deferral Adjustment ($ LCA 14 ctual Idaho Jurisdictional ECPC minus NPC (Assume Actual = PAC-E-21-07 15 LCAR Rate @ Meter ($/MWh PAC-E-21-0716 ID Actual Sales @ Meter (MWh Line 17 LCAR Revenue Collected through Base Rates (Line 15 x Line 1 18 LCAR Adjustmen Line 14 - Line 1 ECAM Deferral19 Total ECAM Deferral (NPC Deferral, EITF 04-6 Adjustment, LCASum of Lines: 12, 13, 120Total ECAM Deferral after 90% Sharin Line 19 x 90 Production Tax Credits (PTCs21 ID Allocated PTCs in Rates ($/MWh PAC-E-21-07 22 ID Actual Sales @ Meter (MWh Line 23 ID PTCs in Rates ($Line 21 x Line 2 24 ID Allocated Actual PTCs ($25 ID PTCs Deferral ($Line 24 - Line 2 Situs Assigned REP QF Adjustmen26 ID REP QF Adjustment ($ Wind Liquidated Damage27 ID Allocated Wind Liquidated Damages ($ Renewable Energy Credits (REC) Revenu28 ID REC Revenue in Rates ($/MWh PAC-E-21-0729 ID Actual Sales @ Meter (MWh Line 30 ID REC Revenue in Rates ($Line 28 x Line 2 31 ID Allocated Actual REC Revenue ($32 REC Revenue Adjustment ($Line 31 - Line 3 33 Total Deferral Sum of Lines 20, 25, 26, 27, 3 34 Interest Rat Order No. 3486 ECAM Balancing Account ($35 Beginning Balanc 36 ECAM Deferral After Sharin Line 237 PTCs Deferral Line 2 38 REP Situs Adjustmen Line 239 Wind Liquidated Damage Line 240 REC Revenue Adjustmen Line 3 41 Less: Monthly ECAM Rider Revenues allocated to ECA42 Interes 43 Total ECAM Deferral Balance ($) Dec-22 Total24.54$ 299,866 7,358,512$ 90,966,98$ 267,860,34$ 2,018,394,44$ 5,589,47 61,277,48 47.92$ 32.94$ 292,81614,032,41$ 126,289,81$ 6,673,90$ 35,322,82$ (7,269)$ 190,65$ 2,568,242$ 30,818,90$ 8.74$ 299,866 2,620,702$ 32,397,49$ (52,460)$ (1,578,588$ 6,614,17 33,934,89 5,952,75$ 30,541,40$ (4.16$ 299,866 (1,248,617$ (1,705,514 (456,897$ 1,388,020$ 85,311$ 634,30$ (2,824)$ (295,039$ (0.07$ 299,866 (20,526$ (73,125 (52,599)$ (130,679$ 5,525,74$ 32,138,01$ 1.00% 38,310,84$ 5,952,75 (456,897 85,311 (2,824 (52,599 (1,928,544 33,425 41,941,478$ 41,941,478$ Rocky Mountain Power Exhibit No. 1 Page 2 of 2 Case No. PAC-E-23-09 Witness: Jack Painter