Slide 1: 2027 Electric and Natural Gas IRPs TAC Meeting No. 5 Agenda
2027 Electric and Natural Gas Integrated Resource Plans Technical Advisory Committee Meeting No. 5 Agenda Friday, February 20, 2026 Virtual Meeting – 1:00 pm to 4:00 pm Pacific Time Topic State Audience • Introduction and Questions from TAC 4 o RCP 4.5 vs. RCP 8.5 o CO2 Transportation Update • DER F
Slide 2: Introductions 2027 Electric & Gas Integrated Resource Planning
Introductions 2027 Electric & Gas Integrated Resource Planning TAC 5 – February 20 , 2026 John Lyons, Ph.D. – Senior Resource Policy Analyst
Slide 3: TAC 5 Agenda
TAC 5 Agenda • Introduction and Questions from TAC 4, John Lyons • RCP 4.5 vs. RCP 8.5 • CO2 Transportation Update • DER Forecast Impact on Electric Distribution System, Erik Lee • Sub-Hourly DER Resource Value Analysis, Jacob Heimbigner • New Electric Resource Options and Cost Forecast, Robert Hugh
Slide 4: Meeting Guidelines
Meeting Guidelines • IRP team is in office Monday – Wednesday; also available by email, phone and Teams for questions and comments • Stakeholder feedback responses shared with TAC at meetings, in Teams and in Appendix • Working IRP data posted to Teams • All TAC meetings will be virtual on Teams • D
Slide 5: Virtual TAC Meeting Reminders
Virtual TAC Meeting Reminders • Please mute mics unless speaking or asking a question • Raise hand or use the chat box for questions or comments • Respect the pause • Please try not to speak over the presenter or a speaker • Please state your name before commenting for the note taker • This is a pub
Slide 6: Hydro Update: RCP 4.5 vs. RCP 8.5
Hydro Update: RCP 4.5 vs. RCP 8.5 • Both RCPs have more generation in the spring, less in the summer, and slightly more in the fall in comparison to BPA modeled flows and generation. • On an annual basis, both RCPs have more generation as compared to the BPA modeled historical flows. 5
Slide 7: Update: RCP 4.5 vs. RCP 8.5
Update: RCP 4.5 vs. RCP 8.5 Comparison of RCP 4.5, RCP 8.5, and Acutal Monthly Average Temperature OS O O 0 NaN gh ad oS oS ob i > > A A > ak ah ak ah ak gh 0 qo Ad no oO PA PAP PM DDD DD Mh DMD DY DM PP PP PP DD MPM PP PPP PA FHM SEI KEM SEG FY SEG GEM SEI FV Ww SF CMW Kew" Average Daily Temperatur
Slide 8: Update: RCP 4.5 vs. RCP 8.5
Update: RCP 4.5 vs. RCP 8.5 • Annual Minimum Average Daily Temperature: RCP 8.5 is 1.11o F greater than RCP 4.5 at the end of the forecasted period. • Annual Maximum Average Daily Temperature: RCP 8.5 is 0.9o F greater than RCP 4.5 at the end of the forecasted period. 7
Slide 9: RCP 4.5 & RCP 8.5 Comparison: Annual Degree Days
RCP 4.5 & RCP 8.5 Comparison: Annual Degree Days Spokane Spokane Klamath Falls La Grande Medford Roseburg CDD = Cooling Degree Days 8 HDD = Heating Degree Days
Slide 10: Summary Forecast Update: Year 2050 RCP 4.5 → 8.5
Summary Forecast Update: Year 2050 RCP 4.5 → 8.5 Heating Degree Days Cooling Degree Days Peak Day Hist. RCP RCP Hist. RCP RCP RCP RCP Area 20y Avg. 4.5 8.5 20y Avg. 4.5 8.5 COR 4.5 8.5 Spokane 6,453 6,091 5,890 586 794 850 -16.5 -14.9 -14.7 Klamath Falls 6,762 6,355 6,156 258 367 440 -7.0 -6.2 -5.4
Slide 11: Cost Assumptions for CO2 Pipeline
Cost Assumptions for CO2 Pipeline *20 Year Pipeline Life Input Measurement Cost Annual O&M Annual for 100-mile Electricity * Wall thickness 0.4 inches Segment Cost 100-mile ($mm) Segment ($mm) CO2 Pipeline 10 inches $237,793 per $4.5 $0.3 Diameter Size Inch-Mile CO2 Pipeline 12 inches $246,206 per $
Slide 12: Number of Trucks Required to Truck or Rail CO2
Number of Trucks Required to Truck or Rail CO2 Input Number of Trucks To Rail 25 Miles Away 30 To Rail 100 Miles Away 52 11
Slide 13: TAC 6 – Monday, March 16, 2026
TAC 6 – Monday, March 16, 2026 (13:00 – 16:00 PDT) Topic State Audience New Gas Resource Options All Gas Liquified Natural Gas Analysis All Gas Wholesale Market Price Scenarios WA/ID Electric All-Source RFP Update WA/ID Electric Economic Forecast and Five-Year Load Forecast All E&G 12
Slide 14: TAC 7 and TAC 8 Topics
TAC 7 – Wednesday, April 15, 2026 (13:00 – 16:00 PDT) Topic State Audience Energy Efficiency Savings Since 2025 IRP OR Gas Hybrid Heat Pump Program Update OR Gas Gas Avoided Cost All E&G Long-Run Load Forecast All E&G End-Use Load Forecast All E&G Wholesale Price Forecast – Stochastic WA/ID Electric
Slide 15: TAC 9 and TAC 10 Topics
TAC 9 – Friday, May 15, 2026 (13:00 – 16:00 PDT) Topic State Audience IRP Generation Option Transmission Planning Studies WA/ID Transmission Distribution System Planning within the IRP WA/ID Dist. Transmission Project Example Evaluation WA/ID Transmission QCC Forecast WA/ID Electric Gas Distribution
Slide 16: TAC 11 Technical Modeling Workshop and TAC 12
TAC 11 Technical Modeling Workshop – Monday, June 15, 2026 (13:00 – 16:00 PDT) Topic State Audience PRiSM Model Tour All E&G Aurora Resource Adequacy Model Tour WA/ID Electric New Resource Cost Model All E&G TAC 12 Wednesday, July 15, 2026 (TDB) Topic State Audience Load & Resource Balance and Metho
Slide 17: TAC 13 and TAC 14 Topics
TAC 13 – Monday, August 17, 2026 (13:00 – 16:00 PDT) Topic State Audience Preferred Resource Strategy Results All E&G Oregon Non-Pipe Alternatives OR Gas Aldyl-A Analysis and Targeted Voluntary Electrification OR Gas IRP/Progress Report Outlines All E&G Next Steps All E&G TAC 14 – Thursday, Septembe
Slide 18: Other Key Dates
Electric Transmission & Distribution 5-Year Plan – October 7, 2026 (10:00 – 12:00 PDT) Topic State Audience Electric Trans Transmission & Distribution 5-Year Plan WA/OR Electric Other Key Dates • Oct 15, 2026 – Draft Electric IRP Released to TAC • Nov TBD 2026 – Virtual Public Meeting • Noon-1pm • 6
Slide 19: DER Potential Study: Feeder Impacts
DER Potential Study: Feeder Impacts February 20, 2026 TAC 5 Meeting Erik Lee – Distribution System Planning Engineer
Slide 20: Agenda
Agenda • DER Potential Study Review • Review Consultant Methodology • Analysis Visualization Examples • Census Block Group w/Largest Fleet EV Load • Feeder w/Portion of Above Allocated to it • 2035 Feeder Capacity Issues from DER (Spoiler: low impact) • 2045 Feeder Capacity Issues from DER (Spoiler:
Slide 21: DER Potential Study Review
DER Potential Study Review • Motivation: WA Clean Energy Implementation Plan (CEIP) • Goal: “To determine a reasonable potential of new generation, storage, and controllable load impacts on a localized basis” • Time Horizon: 2024 – 2050 • Distribution Planning Criteria Specifies a 10 Year Time Horiz
Slide 22: Review of Methodology: Spatio-Temporal Approach
Review of Methodology: Spatio-Temporal Approach • Spatial Granularity: By Census Block Group (476 Polygons) • Temporal Granularity: Hourly Annual Load Shape Model (576-Style) • Base & High Incentive Scenarios • Load Model Components: • Solar • Battery Storage • EV Charging (classes 1-8) • Wind (unus
Slide 23: Review of Methodology: EV
Review of Methodology: EV • LDV market share reaches 100% EV in the 2040– 2050 period, depending on segment • Named Communities lag market adoption by ~10 years unless incentives intervene • Public fleets electrify faster due to state mandates • Tool: NREL EVI-Pro Lite modeling
Slide 24: Review of Methodology: PV
Review of Methodology: PV • Adoption modeled using NREL dGen tool, adjusted for Avista’s rates and NEM policy • Residential adoption varies by propensity scores developed from ACS demographics
Slide 25: Review of Methodology: Storage
Review of Methodology: Storage • Minimal existing storage today • Adoption in the Reference case remains low under current tariffs • High Incentive scenario adds TOU rates and higher resiliency valuation to increase storage adoption
Slide 26: Spatial Partition (Census Block Group) → Feeder Allocation
Spatial Partition (Census Block Group) → Feeder Allocation • Grid Model Spatial Coincidence • Allocate by Feeder Aggregate Circuit Length Single Feeder Allocation → Three Feeder Allocation (Orange, Blue & Purple intersect)
Slide 27: Stacked Waterfall Hourly Plot
Stacked Waterfall Hourly Plot Net Load Batt Charging Solar kW Demand Batt Discharging EV Charging Net Demand Base Load Load | Gen [ Hour ]
Slide 28: Census Block Group (w/ Largest Fleet EV) 2025
Census Block Group (w/ Largest Fleet EV) 2025 • E Trent Ave Area “Stacked Waterfall” • Allocated to: ↑ Load Stacked Left • BEA12F1 ↓ Gen Stacked Right • BEA12F6 • 9CE12F3
Slide 29: Census Block Group (w/ Largest Fleet EV) 2025
Census Block Group (w/ Largest Fleet EV) 2025 • Allocated to: • BEA12F1 “Stacked Waterfall” • BEA12F6 Net Demand ↑ Load View Stacked Left • 9CE12F3 ↓ Gen Stacked • ~75 kW Right
Slide 30: Census Block Group (w/ Largest Fleet EV) 2035
Census Block Group (w/ Largest Fleet EV) 2035 • ~4,100 KW Net “Stacked Waterfall” Peak ↑ Load Stacked Left ↓ Gen Stacked Right • ~16 MW in 2045!
Slide 31: Feeder Example: BEA12F6 2035 (Commercial/Fleet)
Feeder Example: BEA12F6 2035 (Commercial/Fleet) 100% High EV Polygon 80% Ambient Facility Ratings (Dark Blue) Aggregate (1 in 10 Weather Year) Allocated EV Load
Slide 32: Existing Capacity Issue Examples (Summer & Winter)
Existing Capacity Issue Examples (Summer & Winter)
Slide 33: TUR116 2035 (Winter Constraint)
TUR116 2035 (Winter Constraint)
Slide 34: GLN12F2 2035 (Summer Constraint)
GLN12F2 2035 (Summer Constraint)
Slide 35: New Capacity Issues in 2035 from DER Load (3 Feeders)
New Capacity Issues in 2035 from DER Load (3 Feeders) • All 3 Already Very Close to 80% Threshold • Small Differential FEEDER MONTH PK_PCT_BASE PK_PCT_NET DIFF MEA12F1 July 79.4 80.7 1.3 PDL1202 July 79.7 81.6 1.9 NE12F2 July 79.2 82.6 3.4
Slide 36: Maps: Spokane (Left), Lewiston-Clarkston (Right)
Maps: Spokane (Left), Lewiston-Clarkston (Right)
Slide 37: PDL1202 2035 (Clarkston)
PDL1202 2035 (Clarkston) ID: PDL1202 [Base] July 2035 Weekday 15000 Base Load 1as00 MEEV Load 14000 im Battery (Load & Gen) 13500 Solar Gen Net Demand Mm Facility Rating 9 91D 1041 1142 «1213 «1314 IS 1546 1617 1718 1819 1920 2071 21-22 Lead-Gen
Slide 38: MEA12F1 2035 (N Spokane)
MEA12F1 2035 (N Spokane) ID: MEA12F1 [Base] July 2035 Weekday 15000 Base Load 14500 MEEV Load 14000 im Battery (Load & Gen) ras%0 Solar Gen 13000 Net Demand 12500 i Facility Rating 9 91D 1041 1142 «1213 «1314 IS 1546 1617 1718 1819 1920 2071 21-22 Lead-Gen
Slide 39: NE12F2 2035 (N Spokane)
NE12F2 2035 (N Spokane) ID: NE12F2 [Base] July 2035 Weekday 14500 Base Load 14000 MEEV Load 1309 im Battery (Load & Gen) 13000 Solar Gen Net Demand Mm Facility Rating am 9 91D 1041 1142 «1213 «1314 IS 1546 1617 1718 1819 1920 2071 21-22 Lead-Gen
Slide 40: New Capacity Issues in 2045 From DER Load (21 Unique Feeders)
New Capacity Issues in 2045 From DER Load (21 Unique Feeders) PK_PCT_BAS FEEDER MONTH PK_PCT_NET DIFF E 3HT12F4 3HT12F5 July January 78.1 55.7 83 95.2 4.9 39.5 • Mainly Commercial Feeders 3HT12F5 July 59.2 96.7 37.5 3HT12F7 BEA12F2 July January 56.7 62.8 98.1 82.9 41.4 20.1 • Split between Summer &
Slide 41: Key Observations
Key Observations • EV Load is the Biggest Contributor • Improves Utilization Factor (Assuming Shape Hold True) • Commercial/Industrial Area Focus (Fleets Especially) • Solar Offsets Some EV Impact In Summer Peaks • Battery Storage is Negligible • Most Impacts Occur Outside of Current Planning Window
Slide 42: Thank you!
Thank you! AIVISTA
Slide 43: Sub-hourly DER Resource Value Analysis
Sub-hourly DER Resource Value Analysis Technical Advisory Committee Meeting No. 5 February 20, 2026 Jacob Heimbigner, Resource Planning Analyst
Slide 44: Why
Why • Only Model Hourly in Aurora Stochastic. • Commission staff requested DER sub-hourly analysis to ensure Avista captures the full value. Which they believe could materially affect future PRS selections and improve real world operational decisions. 2
Slide 45: Analysis
Analysis • Utilized AVA Load Real Time Dispatch (RTD) pricing for sub-hourly(5 min) and average RTD for hourly dispatch. • Allows to understand the true benefit between hourly and sub-hourly dispatch. • Pricing through CAISO Energy Imbalance Market (EIM). • Modeled Battery Energy Storage System (BES
Slide 46: EIM Avista Load Price
EIM Avista Load Price RTD Hourly AVG RTD 2024 2025 2024 2025 Min Price (386.20) (100.79) Min Price (94.49) (57.45) 1,973.80 1,050.54 1,527.30 492.94 Max Price Max Price Spread 2,360.00 1,151.33 Spread 1,621.79 550.38 Average 41.23 32.69 Average 41.23 32.69 Price Price Median 30.79 31.44 Median 30.93
Slide 47: Actual Day Price Trend
Actual Day Price Trend $120.00 $100.00 $80.00 $60.00 $40.00 $20.00 $- $(20.00) $(40.00) 11 16 10 10 11 12 12 13 13 14 14 15 15 16 17 17 18 18 19 19 20 20 21 21 22 22 23 0 0 1 1 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 Hour Ending Interval Price ($/MWh) Hourly Intrerval Average Price ($/MWh) 5
Slide 48: Interval Price vs Hourly Interval Average Price
$120.00 $100.00 $80.00 $60.00 $40.00 $20.00 $- Interval Price ($/MWh) Hourly Intrerval Average Price ($/MWh) 6
Slide 49: BESS Logic
BESS Logic Max Storage MWh 100 Min Storage MWh 10 Max MW Dispatch 25 Max MW Charge 25 Cycles Per year 365 Round Trip Efficiency 88% 7
Slide 50: BESS Hourly vs. Sub-Hourly Benefit
BESS Hourly vs. Sub-Hourly Benefit 2024 Dispatch 2025 Dispatch Hourly Revenue 1,206,153 804,856 RTD Revenue 1,426,845 962,935 RTD Benefit (Loss) 220,692 158,079 RTM Benefit (Loss) % 18.3% 19.6% 8 Optional footer for data sources, etc.
Slide 51: Demand Response with Immediate Snapback
Demand Response with Immediate Snapback Events 24 Dispatch Hours 3 Snapback Hours 4 MW Dispatch 5 MW Charge 4 MWh Dispatch Total 360 MWh Snapback Total 360 9
Slide 52: DER with Snapback Analysis
DER with Snapback Analysis 2024 Dispatch 2025 Dispatch Hourly Revenue 72,914 24,517 RTD Revenue 74,626 25,194 RTD Benefit (Loss) 1,712 677 RTD Benefit (Loss) % 2.3% 2.8% 10
Slide 53: Supply Side Resource Options
Supply Side Resource Options Technical Advisory Committee Meeting No. 5 February 20, 2026 Robert Hughes, Resource Planning Analyst
Slide 54: Overview and Considerations
Overview and Considerations • IRP supply-side resources are near commercially available technologies with potential for development within or near Avista’s service territory. • Resource costs vary depending on location, equipment, fuel prices and ownership; while IRPs use point estimates, actual cos
Slide 55: Resources Not Modeled in the 2027 IRP
Resources Not Modeled in the 2027 IRP • Coal • Wave/Tidal • Advanced Geothermal • Fusion Reaction • Allam Fetvedt Cycle Power Plants
Slide 56: Resources Modeled
Resources Modeled Resource Fuel Source MW Capacity Heat Rate Capital Available FOM $kW-yr VOM $/MWh Factor % MMBTU / $/kW(2028) Year (2028) (2028) MWh CT Frame Natural Gas 290 10.010 $1,795 2030 $7.15 $5.86 CT Frame Ammonia 145 10.010 $1,944 2030 $19.92 $7.03 CT Frame RNG 145 10.010 $1,795 2030 $19.
Slide 57: Resources Modeled Continued
Resources Modeled Continued Resource Fuel MW MWhs Capacity Capital $/kW Available FOM $kW- VOM $/MWh Source Factor/ RTE (2028) Year yr (2028) (2028) Pumped Hydro Water 400 3,200 80% $4,961 2030 $23.61 $0.76 Pumped Hydro Water 100 2,400 80% $4,477 2030 $23.61 $0.76 Adams Neilson Repower Solar 25 24%
Slide 58: Solar Capital Costs
Solar Capital Costs Overnight Capital Cost ($2028/kW) $2,500.00 Avista 2027 IRP Forecast $2,000.00 $1,500.00 Avista 2025 IRP Forecast $1,000.00 $500.00 $- 6
Slide 59: Solar PPA Price/Implied Energy Payment
Solar PPA Price/Implied Energy Payment 7
Slide 60: Wind Capital Costs
Wind Capital Costs Overnight Capital Cost ($2028/kW) $3,000.00 $2,500.00 Avista 2027 IRP $2,000.00 $1,500.00 $1,000.00 AVA 2025 IRP Forecast $500.00 $- 8
Slide 61: Wind PPA Price/Implied Energy Payment
Wind PPA Price/Implied Energy Payment 9
Slide 62: Baseload Clean Energy
10 Baseload Clean Energy $/MWh $450 $400 $350 $300 $250 $200 $150 $100 $50 $422 $262 $286 266 $223 s $206 $153 $75 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Year —Geothermal (Off System) | —Enhanced Geothermal (Off System) | ——
Slide 63: 4 Hour Battery Capital Costs
4 Hour Battery Capital Costs Overnight Capital Cost ($2028/kW) $2,500.00 $2,000.00 Avista 2027 IRP $1,500.00 $1,000.00 Avista 2025 IRP $500.00 $- 11
Slide 64: Energy Storage PPA Price/Implied Capacity Payment
Energy Storage PPA Price/Implied Capacity Payment 12
Slide 65: Energy Storage PPA Price/Implied Capacity Payment
Energy Storage PPA Price/Implied Capacity Payment 13
Slide 66: Dispatchable Resource Variable vs Fixed Cost
Dispatchable Resource Variable vs Fixed Cost 14
Slide 67: Q&A Thank you!
Q&A Thank you! 15
Slide 68: Electrification Analysis Assumptions
Electrification Analysis Assumptions TAC 5 – February 20, 2026 James Gall, Manager of Resource Analysis
Slide 69: Overview of Methodology
Overview of Methodology • The load forecast will include customer choice/code electrification. • Cadmus will provide its methodology at the April TAC meeting • Additional electrification will be a resource option in the integrated resource selection model (PRiSM) • If electrification is selected, el
Slide 70: Electrification Costs Per Customer (2026$)
Electrification Costs Per Customer (2026$) - Assumes utility energy efficiency applicable rebate - Assumes appliances replaced at end of life (subtracts equivalent equipment replacement from install cost) - Sales tax is the difference in cost between states - Other represents an impact of clothes dr
Slide 71: Residential Space Heating Efficiency Curves
Residential Space Heating Efficiency Curves 5.00 Carrier 45M w/o 4.50 defrost & w/ Auxiliary 4.00 NREL Avg of NW Sites includes w/ 3.50 Auxiliary and HP COP only 3.00 NREL w/o COP 2.50 Auxiliary/Defrost 2.00 Net Efficiency 1.50 Heat Pump Compressor Carrier 1.00 Poly. (Net Efficiency) Poly. (Heat Pum
Slide 72: Proposed Space Heating Efficiency Curve
Proposed Space Heating Efficiency Curve 5.00 4.50 4.56 4.00 4.12 3.50 3.71 3.00 3.32 2.97 2.50 COP 2.65 2.35 2.00 1.96 1.50 1.77 1.57 1.34 1.00 1.00 1.00 1.01 1.02 1.03 1.05 1.06 1.07 0.50 - -30 -20 -10 0 10 20 30 40 50 60 70 Temperture (F) 5
Slide 73: Heat Pump Water Heating
Heat Pump Water Heating • Assumes 3.88 UEF water heater @ 67º • What heater placement determines net COP (garage vs indoors) • Must include make-up heat for indoor placed units • Blended garage at 90% in house and 10% garage Blended HPWH Efficiency 9 8 7 6 5 UEF Reduced due to some HW in 4 basements
Slide 74: Modeling Methodology
Modeling Methodology Water Heat kWhrs/Dth 180 160 • Determine how much natural gas is used each 140 month for each fuel switching category per 120 kWh per Dth customer. 100 80 • Use kWh/Dth efficiency curve for water and 60 40 space heat to estimate electric energy impacts 20 to electric system - -2
Slide 75: Residential Space/Water Heat Impacts (Washington Example- DRAFT)
Residential Space/Water Heat Impacts (Washington Example- DRAFT) Electric (Additions) Natural Gas (Reductions) Appliance Net Annual Winter Peak (kW) Summer Peak (kW) Annual Therms Peak Day Therms (kWh) Res HPWH 1,298 0.2 0.0 170 0.3 Com HPWH 10,587 3.0 0.5 1,307 2.0 Res HP w/ NG Backup 1,977 0.0 0.0
Slide 76: Electric Rate Forecast for Non-Avista Service Area
Electric Rate Forecast for Non-Avista Service Area 30 South Oregon North Oregon 25 WA ID 20 Cents per kWh 15 10 5 0 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 9 WA Gas usage on non-Avista electric assumed be at 22% and
Slide 77: Wholesale Electric Market Price Forecast
Wholesale Electric Market Price Forecast Technical Advisory Committee Meeting No. 5 February 20, 2026 Robert Hughes, Resource Planning Analyst
Slide 78: Market Price Forecast – Purpose
Market Price Forecast – Purpose • Estimate “market value” of resource options for the IRP • Estimate dispatch of “dispatchable” resources • Informs avoided costs • May change resource selection if resource production is counter to needs of the wholesale market Source: NERC 2
Slide 79: Methodology
Methodology • 3rd party software - Aurora by Energy Exemplar • Electric market fundamentals - production cost model • Simulates generation dispatch to meet regional load • Outputs: – Market prices (electric) – Regional energy stack – Transmission usage – Greenhouse gas emissions and cost – Power pla
Slide 80: Wholesale Mid-C Electric Market Price History
Wholesale Mid-C Electric Market Price History Mid Columbia Electric Prices (2/10/2026) $140 Energy Crisis 126 Day Ahead Hour Ahead EIM $120 117 $100 $ per MWh 82 $80 Natural Gas Market 78 Tightens 58 59 $60 56 Cheap 51 49 natural 45 42 Shale Development 43 38 $40 gas, good 32 33 32 33 36 30 hydro 23
Slide 81: 2025 Fuel Mix
2025 Fuel Mix Northwest U.S. Western Interconnect 72% GHG Emission Free 53% GHG Emission Free Source: EIA Annual Generation By State and Producer Report 5
Slide 82: Market Indicators
Market Indicators Daily NG vs On-Peak Electric $100 Mid-C $ per MWh $80 $60 $40 y = 6.7447x + 16.667 $20 R² = 0.442 $0 $0 $2 $4 $6 $8 $10 Stanfield $ per DTh Daily Mid-C Price Standard Deviation Off Peak Implied Market Heat Rate $120 On Peak 18,000 $100 16,000 Power/ Gas x 1000 14,000 $80 $ per MWh
Slide 83: Electric Greenhouse Gas Emissions U.S. Western Interconnect
Electric Greenhouse Gas Emissions U.S. Western Interconnect Source: EIA Emissions are adjusted for generation within the Western Interconnect 7
Slide 84: Modeling Process
Modeling Process We are here 3 Capacity Expansion 2 Input Changes Add new resource 30 yr. hydro with climate forecast 6 Re-Run Capacity 7 Run Full 1 Vendor change 5 Test Year Forecast 8 Run Scenarios Database (Capacity/RPS) 4 Preliminary Expansion NG prices Stochastic Study Stochastic & Deterministi
Slide 85: Aurora Zonal System Map
Aurora Zonal System Map 9
Slide 86: U.S. West Resource Type Forecast
Draft forecast U.S. West Resource Type Forecast Significant changes 2045 to 2028 (aGW) Solar: + 21.7 Wind: + 13.9 Nat Gas: - 9.3 Coal: - 6.1 Nuclear: + 0.5 Other: + 0.2 Total: + 20.9
Slide 87: Northwest Resource Type Forecast
Draft forecast Northwest Resource Type Forecast Significant changes 2045 to 2028 (aGW) Solar: + 3.7 Wind: + 2.8 Nat Gas: - 3.3 Coal: - 0.2 Nuclear: + 1.3 Hydro: + 0.6 Other: + 0.5 Total: + 5.3
Slide 88: Mid-C Electric Price Forecast
Draft forecast Mid-C Electric Price Forecast • Levelized Prices: • $44.95/MWh w/CCA • $40.80/MWh w/o CCA • $37.95/MWh Avista • Forecast includes expected resource additions • Potential for increased prices if new resources don’t come online
Slide 89: Hourly Draft Forecast
Hourly Draft forecast Winter: Dec 16 - Mar 15 Spring: Mar 16 - Jun 15 $130 $130 2028 2035 2040 2025 2028 2035 2040 2025 $110 $110 $90 $90 g < 70 = s70 ———~_ Of Es an a Reso e eo $30 $30 ie 44 $10 $10 SSS Ir -$10 -$10 123 4 5 6 7 8 9 101112 13 14 15 16 17 18 19 20 21 22 23 24 123 4 6 6 7 8 9 10111213
Slide 90: Next Steps
Next Steps • Finalize deterministic case • Conduct stochastic studies and verify resource adequacy • Run scenarios (deterministic/stochastic as appropriate) 14