Slide 1: 2025 Natural Gas IRP Technical Advisory Committee Meeting No. 2 Agenda
2025 Natural Gas Integrated Resource Plan Technical Advisory Committee Meeting No. 2 Agenda Wednesday, April 24, 2024 Virtual Meeting Topic Time (PTZ) Staff Agenda/Meeting Guidelines 10:30 Tom Pardee Action Items 10:40 Tom Pardee Modeling/Assumptions Overview 11:00 Tom Pardee CROME High Level Overvi
Slide 2: 2023 Gas IRP Action Items
AIVISTA 2023 Gas IRP Action Items
Slide 3: Summary of Acknowledgement
Summary of Acknowledgement • Idaho – Acknowledged (November 1, 2023) • Oregon – Pending short term acknowledgment • Washington – No word on acknowledgment 2
Slide 4: Avista – 2023 Gas IRP Actions
Avista – 2023 Gas IRP Actions 1. ETO identified 546,000 therms in the 2023 IRP verses 427,000 therms of planned savings in the 2023 ETO Budget and Action Plan. Avista will work with ETO to meet IRP gross savings target of 568,000 therms in 2024. 2. New program offered by ETO for interruptible custom
Slide 5: IPUC - Recommendations
IPUC - Recommendations 2025 IRP No. Recommendation 1 Staff recommends the Company's 2023 Natural Gas IRP be acknowledged and accepted for filing contingent on the Company submitting a compliance filing with an updated DSM Avoided Cost table that does not include a National Carbon Tax starting in 203
Slide 6: OPUC - Recommendations
OPUC - Recommendations 2025 IRP No. Recommendation 1 Do not acknowledge 8.64 million therms of RNG in 2023. Removed For the IRP Update the Company should update the load forecast with a downscaling methodology using 2 Multivariate Adaptive Constructed Analogs as employed by Oregon State University’s
Slide 7: OPUC Staff - Expectations
OPUC Staff - Expectations 2025 IRP No. Expectation At a TAC meeting for the next IRP, Avista should provide an estimate of the capacity in MW of electrolyzers, renewable generation, and methanation equipment needed in each year to include synthetic methane in the Oregon PRS. The Company should also
Slide 8: OPUC Staff - Expectations
OPUC Staff - Expectations No. Expectation 2025 IRP The Company should conduct a review, comparing projections from this IRP to actuals of their resource assumptions, quantitative 14 least-cost/least risk predictions, and forecasts. 15 Avista should work with the TAC to develop electrification modeli
Slide 9: WUTC Staff - Recommendations
WUTC Staff - Recommendations Topic No. Recommendations Review the Cascade Natural Gas general rate case final order with the TAC and the EAG together, consider how the core tenets of energy justice 1 apply to Avista’s planning processes, and prepare to implement the order’s equity framework. Dedicat
Slide 10: WUTC Staff - Recommendations
WUTC Staff - Recommendations Topic No. Recommendations 16 Continue to refine the methods and approach of leveraging potential assessments for achieving equitable outcomes. 17 Segment customers with different levels of gas to electric conversion costs rather than modifying costs only by scenario. Dem
Slide 11: Secondary Actions and Attachments
Secondary Actions and Attachments 10
Slide 12: OPUC Staff - Requests
OPUC Staff - Requests Request 1: Future IRPs should include a clearer explanation of the PRS, and a more transparent presentation of the assumptions and processes used in creating the PRS, including examples noted by Staff. Request 2: Staff requests Avista engage the TAC in discussion of the value o
Slide 13: OPUC Staff – Attachment A
OPUC Staff – Attachment A • Ratepayer Incentive Value The Ratepayer Incentive Value includes both the cost of the ratepayer to convert and the benefit the ratepayer’s decision to electrify provides to gas system operations and downstream costs. Staff expects the feasibility of conversion to be const
Slide 14: OPUC Staff – Attachment C
OPUC Staff – Attachment C The Company should update its DSP practices and IRP processes to include: 1. Future distribution system planning should identify the rationale for projects as either Safety/General System Reliability, or Customer Growth/Reliability Related to Growth. a. When proposing growt
Slide 15: Modeling and Assumptions Overview
Modeling and Assumptions Overview 1
Slide 16: Model / Process
Expected Load Model Least Cost Resource Solve Model Risk Model (differing load future scenarios) Scenario Assumptions End Use Risk Efficiencies / Objectives Stock Rollover and Input Climate Program/Policy Constraints Model / Process Current Demand Side Weather Demand Side Resource Resources Options
Slide 17: Load Assumptions
Load Assumptions • PRS load input will rely on current known state policy, codes and requirements • WA SBCC will be included in load forecast baseline • Line extension program expirations will be included in forecast baseline - 2027 end date in Oregon - 2024 end date in Washington • Hybrid heating b
Slide 18: Cost Assumptions
Cost Assumptions All quantifiable current and estimated costs: • Interstate pipeline transportation • Storage • Expected cost of natural gas by supply basin (AECO, Malin, Rockies, Stanfield, Station 2, Sumas) • Alternative fuels (RNG, Methanation, Hydrogen – all forms, carbon capture) • Compliance m
Slide 19: Output
Output • An average rate, with power costs, will be provided by scenario • Emissions by scenario • A levelized cost by scenario • A net present value revenue requirement (NPVRR) • Risks • Energy Burden 5
Slide 20: Scenarios
Scenarios Scenarios – Deterministic & Description Monte Carlo PRS Our expected case based on assumptions and costs with a least risk and least cost resource selection. This scenario includes all known policies and orders from Idaho, Oregon and Washington. Assumes 4.5 RCP weather. High Growth on Gas
Slide 21: Scenarios – Deterministic Only
Scenarios – Deterministic Only Scenarios – Description Deterministic Only Low Alternative Fuel A scenario to measure resource selection with a lower-than-expected set of Alternative Costs Fuel costs by source High Alternative Fuel A scenario to measure resource selection with a higher-than-expected
Slide 22: Scenarios – Deterministic Only
Scenarios – Deterministic Only Scenarios – Description Deterministic Only RCP 8.5 Weather Weather will use the RCP 8.5 future RCP 6.0 Weather Weather will use the RCP 6.0 future as the average between RCP 8.5 and 4.5 Resiliency Supply will be selected to create a resilient system No New Natural Gas
Slide 23: Modeling Risk
Modeling Risk • 18 total scenarios • Deterministically solve a set of resources to meet variability in the scenarios for a stochastic set of futures • Run 500 monte carlo futures for the 4 distinct load scenarios to determine risk • Efficient Frontier may be used to select least cost and least risk
Slide 24: Avista CROME High Level Overview
Avista CROME High Level Overview Comprehensive Resource Optimization Model in Excel Michael Brutocao Natural Gas Analyst
Slide 25: Timeline: IRP Modeling Software
Timeline: IRP Modeling Software Prior to 2023 2023 IRP 2025 IRP SENDOUT® PLEXOS® Avista CROME 2
Slide 26: High Level Overview
High Level Overview Select scenario- specific data INPUTS AND Avista CROME REPORTS ASSUMPTIONS • CROME solution data • Inputs and assumptions • Inputs, assumptions, updates templates for are stored here. and constraints are summary statistics and brought together. graphics. • Data is prepared for CR
Slide 27: Solving for Residential, Commercial, and Industrial Loads
Solving for Residential, Commercial, and Industrial Loads Storage Gross Energy Storage Demand Withdrawal Third Party Storage DSM Natural Gas Compliance Injection Mechanisms Program Net Energy Alternative Compliance Demand Fuels Mechanisms Demand Pipeline Electrification Response Network Emission Net
Slide 28: Solving for Transport Customer Loads
Solving for Transport Customer Loads Storage Gross Energy Storage Demand Withdrawal Natural Gas Third Party Storage DSM (From Service Compliance Injection Supplier) Mechanisms Program Net Energy Alternative Compliance Demand Fuels Mechanisms Demand Pipeline Electrification Response Network Emission
Slide 29: NET LOAD
NET LOAD 6
Slide 30: Gross Demand
Gross Demand Considerations: Number of customers by end-use Gross Energy Base use per customer Demand Heating use per customer DSM Weather Net Energy Demand Optimization Decision: N/A Demand Electrification Response Points: All modeled areas and customer classes Net Load Frequency: Daily 7
Slide 31: Demand Side Management
Demand Side Management Considerations: Avoided cost by area and customer Gross Energy class Demand Number of customers by end-use DSM CPA from AEG/ETO Net Energy Demand Inputs: UCT (ID), TRC (WA, OR) Demand Electrification Points: All modeled areas and customer Response classes Net Load Frequency: D
Slide 32: Demand Response
Demand Response Considerations: Cost Gross Energy Demand Available “supply” by program, area and customer class DSM Optimization Decision: Quantity “purchased” Net Energy Demand Decision Points: All modeled areas and customer Demand Response Electrification classes Net Load Decision Frequency: Daily
Slide 33: Electrification
Electrification Considerations: Cost Gross Energy Demand Available “supply”* DSM Optimization Decision: Quantity “purchased” Net Energy Demand Decision Points: Residential and commercial classes (OR, WA) Demand Electrification Response Decision Frequency: Annual Net Load * This is constraining the o
Slide 34: SERVED LOAD
SERVED LOAD 11
Slide 35: Natural Gas
Storage Natural Gas Considerations: Cost Storage Withdrawal Optimization Decision: Quantity purchased Storage Natural Gas Injection Decision Points: AECO Stanfield Alternative Fuels Malin Station 2 Pipeline Rockies Sumas Network Decision Frequency: Daily Served Load Unserved Load 12
Slide 36: Alternative Fuels
Storage Alternative Fuels Considerations: Cost Storage Withdrawal Available supply * Max blend percent *1 Storage Natural Gas Injection Optimization Decision: Quantity purchased Alternative Fuels Decision Points: Hydrogen (7 forms) Pipeline Network RNG (5 forms) Synthetic methane (3 forms) Served L
Slide 37: Storage
Storage Storage Considerations: Min/max volume * Storage Withdrawal Max daily injection/withdrawal * Capital & overhead Storage Natural Gas Carrying rate Injection Alternative Fuels Optimization Decision: Quantity injected/withdrawn Pipeline Network Decision Points: Jackson Prairie Served Load Decis
Slide 38: Pipeline Network
Storage Pipeline Network Considerations: Flow capacity * Storage Withdrawal Reservation rate Variable rate (flow charge) Storage Natural Gas Fuel loss Injection Alternative Fuels Optimization Decision: Segment flow Pipeline Network Decision Points: All pipeline segments in network Served Load Decisi
Slide 39: Unserved Load
Storage Unserved Load Considerations: Cost Storage Withdrawal Optimization Decision: Quantity unserved Storage Natural Gas Injection Decision Points: All modeled areas and customer Alternative Fuels classes Pipeline Network Decision Frequency: Daily Served Load Unserved Load 16
Slide 40: EMISSIONS
EMISSIONS 17
Slide 41: Natural Gas & Alternative Fuels
Natural Gas & Alternative Fuels Natural Gas Third Party Considerations: Carbon emissions (+Upstream Compliance Emissions) Mechanisms Alternative Program Optimization Decision: Quantity purchased Compliance Fuels Mechanisms Decision Points: Same as in served Emission Decision Frequency: Annual, daily
Slide 42: Third Party Compliance Mechanisms
Third Party Compliance Mechanisms Third Party Considerations: Cost Natural Gas Compliance Mechanisms Available supply * Program Alternative Compliance Fuels Mechanisms Optimization Decision: Quantity purchased Decision Points: Renewable thermal credits (3 forms) Emission Carbon capture (4 forms) Con
Slide 43: Program Compliance Mechanisms
Program Compliance Mechanisms Third Party Considerations: Cost Natural Gas Compliance Mechanisms Available supply * Program Alternative Compliance Fuels Mechanisms Optimization Decision: Quantity purchased Decision Points: Allowances (CCA) Emission Offsets (CCA) Constraints CCIs (prior CPP) Non- Com
Slide 44: Non-Compliance
Non-Compliance Third Party Considerations: Cost Natural Gas Compliance Mechanisms Alternative Program Optimization Decision: Quantity Compliance Fuels Mechanisms Decision Points: Climate Commitment Act Prior Climate Protection Program Emission Constraints Decision Frequency: Compliance period, annua