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HomeMy WebLinkAbout20240329PAC to Staff 39-47.pdf _ ROCKY MOUNTAIN POWER A DIVISION OF PACIFICORP 1407 W North Temple, Suite 330 Salt Lake City, Utah 84116 March 29, 2024 Monica Barrios-Sanchez Commission Secretary Idaho Public Utilities Commission 11331 W. Chinden Blvd. Bldg. 8, Ste. 201-A Boise, ID 83714 monica.barriossanchez(ir,puc.Idaho.gov Secre1M(-,1)uc.idaho.9ov (C) RE: ID PAC-E-23-17 IPUC Set 4 (39-47) Please find enclosed Rocky Mountain Power's Responses to IPUC 41h Set Data Requests 39-47. Also provided are Attachments IPUC 39-1 and 40. Provided via BOX are Confidential Attachments IPUC 39-2, 44, and 47. Confidential information is provided subject to protection under IDAPA 31.01.01.067 and 31.01.01.233, the Idaho Public Utilities Commission's Rules of Procedure No. 67—Information Exempt from Public Review, and further subject to the protective agreement executed in this proceeding. If you have any questions, please feel free to call me at(801)220-2313. Sincerely, /s/ Mark Alder Manager, Regulation Enclosures PAC-E-23-17/Rocky Mountain Power March 29, 2024 IPUC Data Request 39 IPUC Data Request 39 Although the Company discusses the advantages and disadvantages of seasonal and time-of-use pricing for the Export Credit Rate (ECR); the Company does not provide any numerical examples for the energy component of the ECR in the On- Site Generation Study (Study). Please provide hypothetical seasonal pricing for the energy component using the Schedule 1 seasons (June to October and November to May). Please include the worksheets (with formulas enabled) used to determine the pricing. Response to IPUC Data Request 39 Please refer to Attachment IPUC 39-1 which provides the summary of seasonal energy pricing and Confidential Attachment IPUC 39-2 which provides the calculations supporting the summary of seasonal energy pricing. Note: the information provided has not yet been adjusted for line losses, which would increase both summer and winter values by the same percentage. Compensation under the summer and winter rates would be identical to the annual rates previously provided so long as the split of summer and winter volumes aligned with the sample export profile. Energy values are generally higher in the summer.Note: while the June-October summer season is only five months long, as a result of longer days and the higher angle of the sun in the sky, slightly over half of the annual exports occur in that timeframe in the export profile. Confidential information is provided subject to protection under IDAPA 31.01.01.067 and 31.01.01.233, the Idaho Public Utilities Commission's Rules of Procedure No. 67—Information Exempt from Public Review, and further subject to the non-disclosure agreement(NDA) executed in this proceeding. Recordholder: Dan MacNeil Sponsor: Dan MacNeil PAC-E-23-17/Rocky Mountain Power March 29, 2024 IPUC Data Request 40 IPUC Data Request 40 In its responses to Production Requests No. 5 and 8, the Company showed that the Loss of Load Probability (LOLP)distribution depends significantly on the test year-which in turn affects the ECR avoided capacity value. Please address the following issues: (a) Please provide a list of the test years and LOLP distributions that the Company calculated in the 2021 Integrated Resource Plan (IRP) and in the 2023 IRP; (b) Please provide the 12-month by 24-hour(12-24) distributions for the 2026 test year from both IRPs. If the 2023 IRP did not calculate a 2026 test year distribution, provide the next closest test year distribution; and (c) For these two distributions, please provide the resulting avoided capacity value (using the proxy Utah export data). Response to IPUC Data Request 40 The Company assumes that the reference to "No. 5 and 8" are intended to be references to the Company's responses to IPUC Data Request 5 and IPUC Data Request 8. Based on the foregoing assumption, the Company responds as follows: (a) The Company prepared a 2030 loss of load probability (LOLP) distribution that was filed with PacifiCorp's 2021 Integrated Resource Plan (IRP)using a portfolio that was close to the 2021 IRP preferred portfolio, and later calculated LOLP distributions using the 2021 IRP preferred portfolio for 2024, 2028, 2032, 2036 and 2040. The Company has not prepared LOLP distributions for any years based on PacifiCorp's 2023 IRP. (b) Please refer to Attachment IPUC 40 which provides the LOLP distribution and capacity contribution for the export profile based on the 2026 test year, calculated as the average of the available values for 2024 and 2028 using the 2021 IRP. The Company does not have an LOLP distribution for the 2023 IRP. Please refer to the Company's response to subpart(a) above. (c) Please refer to the Company's response to subpart(b) above. Recordholder: Dan MacNeil Sponsor: Dan MacNeil PAC-E-23-17/Rocky Mountain Power March 29, 2024 IPUC Data Request 41 IPUC Data Request 41 The Company's calculation of the export capacity factor(Appendix 4.2, Summary Tab, column C, rows 4 to 23) yields an identical value of 9% for each of the 20 years-which could change over time. Staff traced the source of this value and found that the Company derived each year's capacity factor from only one year 12-24 Hourly Capacity Factor distribution-the hourly distribution of the Utah proxy data. In effect, the capacity factor for each of the 20 future years is equal to the capacity factor of the current year's exports. This highlights one of the problems with providing a 20-year forecast of the ECR. Please provide the following information: (a) Please explain why the Company forecasts the ECR value for each of the 20 years when various ECR component values are based on recent historical data; and (b) Please discuss the pros and cons of updating the various ECR component values and discuss possible update frequencies for each component. Response to IPUC Data Request 41 Referencing the Company's calculation of the export capacity factor(Appendix 4.2), the Company responds as follows: (a) The hourly export profile is largely a result of solar insolation, with a limited effect related to customer load, therefore, the Company does not anticipate dramatic changes over time. Customer load does have a relationship with prices—high loads would result in low exports and could be more likely to coincide with high energy prices, while low loads would result in high exports and could be more likely to coincide with low energy prices. The available historical export profiles and energy imbalance market(EIM) data indicate that exports tended to occur when prices were slightly below average in 2021, while they occurred when prices were slightly above average in 2022. Within each year, there are months where the value of exports were both above and below average. Please refer to the Company's response to IPUC Data Request 39, specifically Confidential Attachment IPUC 39-2, tab "CZ6B EIM Summary"which provides details. This indicates that prices are likely being more heavily impacted by other factors. The 20-year forecast similarly is primarily reflective of the Company's system costs, and not particularly related to the export profile. (b) Regarding updating export credit rate components: - Energy: This is the vast majority of the export credit rate (ECR). A rate based on historical EIM prices is inherently accurate and transparent, since PAC-E-23-17/Rocky Mountain Power March 29, 2024 IPUC Data Request 41 those prices are public, making it easy to calculate and review. Annual updates are possible, though given that the rate effective period will always lag the historical data, less frequent rate adjustments may be sufficient and help smooth out volatility. For a forecasted rate, the most likely source is PacifiCorp's Integrated Resource Plan (IRP), which is published every two years. The IRP does not reflect near-term changes, as assumptions are locked down well before the publication date, and IRP acknowledgment, where applicable, occurs even later, however results from the IRP could be used to set ECRs on a prospective basis. - Capacity (Generation, Transmission, Distribution): These costs are forecasted in each IRP, and generally do not change significantly from IRP to IRP, however, the capacity contribution and deficiency period may change and impact pricing. For example, based on PacifiCorp's 2023 IRP, generation capacity payments would occur in 2024, rather than starting in 2026 based on PacifiCorp's 2021 IRP. To the extent a clear methodology is developed to use specified inputs from the IRP or actual operations, updates to capacity could occur annually, or with each IRP. However, it may be simpler to leave some or all of the capacity components in place for a length of time, such as between rate cases, and address them holistically with other retail rate components. - Line Losses: Line losses are primarily a function of energy value, with a small component associated with capacity value. Updating the total line loss value whenever energy value changes is appropriate. The line loss percentages are usually addressed in general rate cases, therefore, leaving them at the levels identified in the most recent GRC is recommended. Given the limited size of the change, any update to line loss percentages at the completion of a GRC would likely be incorporated at the next regularly scheduled update. - Integration: These costs are forecasted in each IRP, and are a relatively small portion of the total, so any update could be incorporated at the next regularly scheduled update. - Risk: These costs are forecasted in each IRP, and are a relatively small portion of the total, so any update could be incorporated at the next regularly scheduled update. Recordholder: Dan MacNeil Sponsor: Dan MacNeil PAC-E-23-17/Rocky Mountain Power March 29, 2024 IPUC Data Request 42 IPUC Data Request 42 Section 4.5 discussed the value of avoided risk. Please answer the following: (a) Please explain in more detail the underlying concepts of this value; (b) Please explain the underlying data that the Company used to determine the value; (c) Please explain the calculational steps the Company used in Appendix 4.2 to determine the value; and (d) Please explain if the value of avoided risk would be embedded in an EIM- based avoided energy cost that was regularly updated. Response to IPUC Data Request 42 (a) The forecast of energy values presented in the Company's Application in this proceeding are based on a deterministic Integrated Resource Plan (IRP) study with normal conditions: expected market prices, median load and hydro and average thermal outages. In reality, each of these variables is likely to be higher or lower than the normal level. Some combinations of conditions, such as high load and high thermal outages are likely to result in very high costs, such as administrative pricing during resource shortfalls, while the opposite, low load and low thermal outages, results in relatively modest benefits in avoided fuel. As a result, the average value of the range of outcomes may be higher than the single normalized value. The incremental cost in excess of the normalized value is characterized as a risk adjustment. (b) Within the IRP, in addition to deterministic studies, the Company performs stochastic analysis with varying combinations of market prices, load, hydro, and thermal outages. Because many iterations are performed, to assess different potential combinations, the granularity of the studies was reduced and the medium-term (MT) PLEXOS model was used, instead of running every hour of every year, as in the short-term deterministic analysis. Please refer to the Company's response to IPUC Data Request 39, specifically Confidential Attachment IPUC 39-2. The marginal energy value of each energy efficiency (EE) resource is reported by year for each of the iterations, as shown in column V on tab "Risk". Idaho EE options were used as a proxy for the export profile. This value is reported by PLEXOS but is equivalent to the energy value used for the export profile, which also reflects a defined hourly energy profile multiplied by the locational marginal price (LMP) reported by PLEXOS. Because the MT model is not as granular as the hourly short-term (ST) model, the two values are not directly comparable, however, it is reasonable to assume that the variance in the MT result among different PAC-E-23-17/Rocky Mountain Power March 29, 2024 IPUC Data Request 42 combinations of conditions is comparable to what would be identified in the ST model, had it been run under all of those conditions, and that the measured variance for EE would be similar to the variance for the export profile. (c) As described in the Company's response to subpart(b) above, the PLEXOS model reports the energy value of each resource. The values for Idaho EE resource were reported by iteration from the MT model results in the 2021 IRP. The risk adjustment is converted to a percentage by dividing the standard deviation by the mean value for each EE resource in each year. The risk percentage specific to each year is then applied to the hourly energy value of the export profile. (d) Energy imbalance market (EIM)pricing would reflect actual market prices, loads, hydro and thermal availability, therefore, it would reflect the avoided cost from the specific combination of conditions that actually occurred. As a result, the risk adjustment reflected in the Company's Application in this proceeding would not be necessary. Recordholder: Dan MacNeil Sponsor: Dan MacNeil PAC-E-23-17/Rocky Mountain Power March 29, 2024 IPUC Data Request 43 IPUC Data Request 43 Appendix 8.2 provides the wind and solar integration costs approved in Order No. 34966 (Case No. PAC-E-20-14). However, the Company used the solar integration costs from the 2021 IRP Appendix F-Flexible Reserve Study (Appendix 8.1)to calculate the ECR. Please reconcile the two sources and clarify the Company's intent for including solar integration costs in an ECR. Response to IPUC Data Request 43 The Company would recommend, whenever the export credit rate (ECR) is updated, it would include either: (a) Integration costs from the most recently published Integrated Resource Plan (IRP). This would incorporate the most recent integration results faster. This may be appropriate if the ECR updates are infrequent and subject to extensive review. (b) Integration costs currently approved by the Idaho Public Utilities Commission (IPUC) for use with qualifying facility (QF) pricing. This would incorporate the integration results after an opportunity for more thorough review. This may be appropriate if the ECR updates are frequent and have an objective list of required update components, with less extensive review. (c) The type of update could also determine the source, with a limited set of well- defined annual updates relying upon option (b) above, while a more comprehensive update in a general rate case (GRC) or stand-alone export credit proceeding might rely upon option (a) above. Given the size of the integration cost, relative to the ECR, the Company recommends that the integration costs reflect readily available information and not require significant review as part of the export credit update. Therefore the Company would recommend that the IPUC specify which specific integration costs should be reflected in each update. Note: the Company does not have a strong preference among the options described above. Note also that the Company currently has an open proceeding to update integration costs (Case No. PAC-E-23-24)which is based upon results in the 2023 IRP. If the updated integration costs are approved in that proceeding, they would be the same as in the most recently published IRP. Recordholder: Dan MacNeil Sponsor: Dan MacNeil PAC-E-23-17/Rocky Mountain Power March 29, 2024 IPUC Data Request 44 IPUC Data Request 44 With its Study Supplement, the Company submitted an updated Appendix 4.2 (Supplemental Appendix 4.2) in response to Staffs concerns over the prevalence of confidential information. Please answer the following and, wherever possible, provide public information separately from confidential information. (a) Please provide a list of inputs, calculations, and other information present in confidential Appendix 4.2 that were excluded from Supplemental Appendix 4.2; (b) Please provide work papers supporting the calculations for each export credit cost component (Component) excluded. If not already provided, please include any other workpapers referenced by the calculations contained in these work papers; and (c) For each Component, input data set, or calculation excluded, please explain how the Component is considered confidential under Idaho Code § 7 4-107. Response to IPUC Data Request 44 Please refer to Confidential Attachment IPUC 39 -2 for a complete workpaper supporting the calculations in Appendix 4.2 and Appendix 4.3. This attachment includes one additional tab "Seasonal" with calculations specific to data request IPUC 39 but otherwise supports Appendices 4.2 and 4.3 as filed. (a) The Company treats the following as confidential: - Hourly energy and operating reserve prices, reported by the PLEXOS model. - The Company's hourly Idaho load forecast. - Risk-related calculations specific to energy efficiency (EE)programs, including energy value by stochastic iteration and associated statistics. - Hourly loss of load probability (LOLP)details could be treated as confidential, however, given the vintage of the available results based on PacifiCorp's 2021 Integrated Resource Plan(IRP), the Company did not opt for confidential treatment in this instance. - Details on the calculation of transmission and distribution capacity credits, though the resulting forecasted values are publicly available in Table 7.10 on page 211 of Volume I in PacifiCorp's 2021 IRP. PAC-E-23-17/Rocky Mountain Power March 29, 2024 IPUC Data Request 44 Note: the Company is not treating the export credit profile (based on historical exports) as confidential, nor energy imbalance market(EIM)prices are publicly available. (b) Please refer to the Company's response to IPUC Data Request 39, specifically Confidential Attachment IPUC 39-2 as describe above. For additional details on transmission and distribution capacity credits, please refer to Confidential Attachment IPUC 44. (c) The Company's price and load forecasts are commercially sensitive, as they indicate the Company's price sensitivity, willingness to transact, and resource needs, which if known by other market participants could result in less favorable pricing for sales and purchases. Risk-related calculations similarly provide an indication of the Company's price sensitivity. Confidential information is provided subject to protection under IDAPA 31.01.01.067 and 31.01.01.233, the Idaho Public Utilities Commission's Rules of Procedure No. 67—Information Exempt from Public Review, and further subject to the non-disclosure agreement (NDA) executed in this proceeding. Recordholder: Dan MacNeil Sponsor: Dan MacNeil PAC-E-23-17/Rocky Mountain Power March 29, 2024 IPUC Data Request 45 IPUC Data Request 45 With its Study Supplement, the Company submitted an updated Appendix 4.3 (Supplemental Appendix 4.3) in response to Staffs concerns over the prevalence of confidential information. Please answer the following and wherever possible, provide public information separately from confidential information. (a) Please provide a list of inputs, component, calculations, and other information present in confidential Appendix 4.3 that were excluded from Supplemental Appendix 4.3; (b) Please provide work papers supporting the calculations for each Component excluded. If not already provided, please include any other work papers referenced by the calculations contained in these work papers; and (c) For each Component, input data set, or calculation excluded, please explain how the Component is considered confidential under Idaho Code § 7 4-107. Response to IPUC Data Request 45 Please refer to the Company's response to IPUC Data Request 44. Recordholder: Dan MacNeil Sponsor: Dan MacNeil PAC-E-23-17/Rocky Mountain Power March 29, 2024 IPUC Data Request 46 IPUC Data Request 46 In response to Production Request No. 15, the Company provided the worksheet "Resource Options 18609 P02 MM CET A CONF" referenced by the formulas in confidential Appendix 4.2. Please answer the following: (a) Please define the type of resource used to value the avoided cost of capacity; (b) Please explain how the Company selected this resource; (c) Please explain what other resources the Company considered and why they were not used to value the avoided cost of capacity; and (d) Please explain if this is the same resource used to value the avoided cost of capacity for the Company's DSM programs. Response to IPUC Data Request 46 The Company assumes that the reference to "No. 15"is intended to be a reference to the Company's response to IPUC Data Request 15. Based on the foregoing assumption, the Company responds as follows: Please refer to the Company's response to IPUC Data Request 39, specifically Confidential Attachment IPUC 39-2, tab"Gen Capacity"which provides additional details supporting the calculation of the referenced generation capacity costs. (a) The referenced generation capacity resource is a non-emitting peaker, assumed to be located in the Willamette Valley bubble, located in Oregon. (b) Peaking resources are expected to operate at a relatively low capacity factor (CF), and thus would generate relatively low energy benefits. In contrast, resources with high Us would provide energy benefits to customers throughout the year which would help defray their costs and would reduce the revenue requirement impact when they go in service. PacifiCorp's 2021 Integrated Resource Plan (IRP) assumed that the economic life of natural gas resources was at risk of being reduced for environmental compliance, and that the annualized cost would exceed that of a non-emitting peaking resource as a result. There was limited variation in build costs for non-emitting peaking resources by location in PacifiCorp's 2021 IRP. The Willamette Valley, Oregon resource has assumed costs that were slightly higher than the other locations (an increase of less than 10 percent), but this is well within the potential range of cost variation for this resource type, which is not in operation today. The Company's calculation is based on the net cost of capacity, i.e. the fixed costs of the resource less the net benefits of the energy PAC-E-23-17/Rocky Mountain Power March 29, 2024 IPUC Data Request 46 it produces, after accounting for variable costs and fuel. The referenced peaking resource was not expected to operate, so it creates no net benefits. After accounting for capacity contribution impacts, other resource types, like wind, solar, or battery storage, are expected to have a net cost of capacity that is higher than for the peaking resource. The net cost for those resources may also be volatile over time, as their energy benefits and capacity contribution will vary with the mix of resources in the preferred portfolio. (c) Please refer to the Company's response to subpart(b) above. (d) The resource referenced in the Company's response to subpart (a) above is the same resource used to value generation capacity for avoided costs of the Company's demand-side management (DSM) programs. However, in 2024, the Company will begin to use values sourced from PacifiCorp's 2023 1". Recordholder: Dan MacNeil/Peter Schaffer Sponsor: Dan MacNeil/Peter Schaffer PAC-E-23-17/Rocky Mountain Power March 29, 2024 IPUC Data Request 47 IPUC Data Request 47 Study Scope item No. 15 directed the Company to quantify the potential value of grid stability, among other items. The Company's Study Supplement, states that on-site generation paired with batteries such as the Company's Wattsmart Batteries pilot program can provide this benefit. Please answer the following questions: (a) Please explain how the grid stability benefit of on-site generation paired with storage is captured in the current design of the Wattsmart Battery pilot program; (b) Please provide the benefit calculation workpapers for the Wattsmart Battery Pilot program in excel format with equations intact and enabled. Please specify where the grid stability benefit is captured in the calculation and include any other work papers referenced in these calculations; (c) Please describe in detail any differences in the source of avoided cost value streams (e.g., energy, capacity, transmission, distribution, etc.)between the Wattsmart Batteries program and those used to value the export credit costs from table 4.1 of the Study; (d) Please explain if the Wattsmart Batteries Pilot program has realized these benefits. If so, please provide supporting data. If not, why not? (e) Please explain why it may or may not be appropriate to include a grid stability credit/benefit in a potential export credit rate for systems with paired battery storage; and (f) Please explain why the Company did not quantify the grid stability benefits of the Wattsmart Battery program in the Study. Response to IPUC Data Request 47 (a) The WattSmart Battery program is able to provide grid services that provide grid stability benefits including frequency regulation services, peak load management, circuit congestion relief, and backup power. The program is designed to allow for utility integration to allow for automated fast dispatch of enrolled batteries for frequency response. Additionally, the program allows for longer duration dispatch providing peak load management and circuit congestion relief. Lastly, the program is structured to allow customers to maintain a reserve of energy in their battery systems should backup power be necessary. (b) Please refer to Confidential Attachment IPUC 47 which provides avoided costs used for the WattSmart Battery Program for the Company's 2022 Energy Efficiency and Peak Reduction Annual Report. Grid stability benefits of peak load PAC-E-23-17/Rocky Mountain Power March 29, 2024 IPUC Data Request 47 management and circuit congestion relief are reflected in the generation and distribution capacity benefits. (c) The WattSmart Battery program and table 4.1 of the export credit study use the same locational marginal price (LMP) for avoided energy values and the same transmission and distribution deferral values. The WattSmart battery program relies on the capacity deferral value used for the Company's interruptible contracts in Idaho to maintain consistency with previously approved demand response (DR). (d) Pursuant to the Company's 2022 Energy Efficiency and Peak Reduction Annual Report, the Company realized the benefits estimated in Confidential Attachment IPUC 47 based on actual dispatch during the year. (e) Potential grid stability benefits for systems paired with battery storage are realized when batteries can be deployed via a distributed battery grid management system. Customers must enroll in a battery management program and allow a grid operator to dispatch batteries during a peak load event. Participating customers are compensated with enrollment and participation incentives. It is not appropriate to include a grid stability credit/benefit for systems paired with batteries in an export credit rate (ECR) because only customers who participate in a battery management program provide grid stability benefits and these customers are compensated for these benefits through enrollment and participation incentives. If these benefits were included in an export credit, non-participating customers would be compensated without providing any benefit and participating customers would be compensated twice. (f) The Company did not estimate the grid stability benefits of the Wattsmart Battery program in the export credit study because these benefits are compensated through program incentives and do not belong in an export credit. In addition, analysis of the Wattsmart Battery program was not included in the study scope as defined by Order No. 34753 in Case No. PAC-E-19-08. Confidential information is provided subject to protection under IDAPA 31.01.01.067 and 31.01.01.233, the Idaho Public Utilities Commission's Rules of Procedure No. 67 —Information Exempt from Public Review, and further subject to the non-disclosure agreement(NDA) executed in this proceeding. Recordholder: Peter Schaffer/Travis Walker Sponsor: Peter Schaffer/Lee Elder