Item 12- Staff briefing and Modeling Overview for the Resource, Generation, and Climate Protection Plan — original pdf

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Round II Modeling Results Austin Energy Resource, Generation and Climate Protection Plan to 2035 Michael Enger Vice President, Energy Market Operations & Resource Planning October 21, 2024 © Austin Energy Agenda Recap of Modeling Timeline Round II Modeling Results Insights From Modeling To Date Discussion & Next Steps 2 Modeling Timeline Modeling Inputs & Assumptions to EUC 7/10/24 Portfolios + Scenarios to EUC 8/8/24 Ascend Modeling Overview to EUC 9/9/24 Modeling Results #1 to EUC 9/30/24 Modeling Results #2 to EUC 10/21/24 JUNE JULY AUG SEPT OCT Data Sources 7/8 Webber Draft Report 7/31 DNV Study Preliminary Results 1st Model Runs 2nd Model Runs 7/15 EUC Feedback on Inputs & Assumptions 8/12 EUC Input on Portfolios + Scenarios 10/1 – 10/4 EUC Office Hours to Refine Portfolios 3 Transitioning to Plan Development Resource Modeling Resource Planning  How well do different resource mixes mitigate reliability, liquidity and load zone price separation risk?  What are the tradeoffs in reliability, cost, and emissions between different portfolio mixes?  What insights did we learn from the modeling process that should inform the plan?  What are the key characteristics from the modeled portfolios that mitigate risk and balance tradeoffs? 4 Round II Modeling 5 Round II Portfolios Austin Energy and EUC selected four new portfolios to improve our understanding of risks and tradeoffs 14 • Variation of Portfolio 10 with incremental new local storage + gas • Tests “floor” level of local resources needed to maintain reliability 15 • Variation of Portfolio 12 with more local solar + storage + DR • Tests cost/reliability of aggressive mix of DSM + storage only • Variation of Portfolio 12 with larger ratio of storage to solar + more DR • Tests relative performance of different solar + storage mixes • Maintains Decker/Sand Hill past 2034 • Identical to Portfolio 12 with Decker/Sand Hill operating past 2034 16 17 6 Reference Guide to New Portfolios REF # DESCRIPTION 10 14 12 15 16 395 MW local storage, 100% DNV projections, 65% RE (1,800 MW wind/solar PPAs), REACH on gas, Decker/Sand Hill run through 2035 125 MW local storage (100 MW 4-hr, 25 MW 2-hr), 200 MW local peakers, 100% DNV projections (431 MW local solar, 270 MW demand response), 250 MW import capacity increase, 65% RE (1,800 MW wind/ solar PPAs), REACH on gas, Decker/Sand Hill run through 2035 525 MW local storage (300 MW 12-hr, 200 MW 4-hr, 25 MW 2-hr), 700 MW local solar, 300 MW demand response, 100% RE as % of load (2,500 MW wind/solar PPAs), 100% CF, REACH on gas, retire Decker/Sand Hill 2034 625 MW local storage (350 MW 12-hr, 250 MW 4-hr, 25 MW 2-hr), 960 MW local solar, 325 MW demand response, 250 MW import capacity increase, 100% CF, 100% RE as % of load (2,500 MW wind/solar PPAs), REACH on gas, retire Decker/Sand Hill in 2034 525 MW local storage (300 MW 12-hr, 200 MW 4-hr, 25 MW 2-hr), 860 MW local solar, 400 MW demand response, 250 MW import capacity increase, 100% RE as % of load (2,500 MW wind/solar PPAs), REACH on gas, Decker/Sand Hill run through 2035 17 Same as 12 except Decker/Sand Hill run through 2035 7 Transmission Import Capacity Portfolios 14-16 include 250 MW increase of import capacity in 2031  When the lines we use to bring electricity into the service territory get overloaded (“local congestion”), Austin Energy can experience higher costs and higher reliability risk  Caused by high load, reduced local generation, issues with transmission system, or some combination of these 8 Scenarios Future states (2025-2035) through which portfolios are stress-tested to measure risk to Austin Energy Austin Energy Load Uses higher load growth projection from Webber Energy Group study Extreme Local Congestion Simulates local generation and/or transmission outages Extreme Events Summer heat, winter storm, low wind days Natural Gas Prices Gas price increases 9 Important Context for this Discussion Models provide information not a specific plan or recommendation The following slides show data results associated with preliminary modeling efforts for the Resource, Generation and Climate Protection Plan to 2035. These results do not reflect a recommendation, and they do not reflect a plan. These results are for informational purposes only. All modeling reflects the input assumptions coordinated with the Electric Utility Commission earlier this year. 10 Round II Portfolios Demand-Side Management vs. DNV Market Potential Study DSM targets in Portfolios 15-17 exceed the maximum economic market potential from recent DNV market potential study Max Economic Market Potential from DNV Study Portfolio 14 Portfolio 15 Portfolio 16 Portfolio 17 540 540 540 360 325 269 400 300 431 960 860 700 1200 1000 800 W M 600 400 200 0 Energy Efficiency Demand Response Local Solar 11 Round II Modeling Portfolio Comparison – Net Cost 12 Net Cost  “Net Cost” = Total capital + O&M costs to generate power – Total revenue from sale of power for a given portfolio mix.  Capital costs for new assets amortized (spread out evenly) over expected life of asset.  O&M costs include fuel, personnel, regular maintenance, etc.  To compare a single “Net Cost” value across portfolios we use the Net Present Value (NPV) of the annual net costs for the 20-year period 2025-2045 using 7.8% discount rate. 13 Net Present Value of 20-Yr Annual Net Costs ($B) B $ 6.0 12.0 10.0 8.0 4.0 2.0 - 14 15 16 17 Portfolio # UPLAN - Normal Conditions Ascend - Mean Ascend P5-P95 Spread 14 Net Present Value of 20-Yr Annual Net Costs ($B) – All Scenarios 25.0 20.0 B $ 15.0 10.0 5.0 - 14 15 Portfolio # 16 17 Normal Conditions High Congestion Scenario High Load Growth Scenario Extreme Weather Scenario 15 Net Present Value of 20-Yr Annual Net Costs ($B) – Sensitivity of Forward Battery Costs ) B $ ( t s o C t e N 12.00 11.00 10.00 9.00 8.00 7.00 6.00 5.00 4.00 3.00 2.00 1.00 - 14 15 16 17 AE 20-yr NPV Net Cost NREL Forward Cost Estimate - 20-yr NPV Net Cost Portfolios 15-17: Average cost difference is 2% ($190M) using NREL Cost Estimates 16 Bill Impact  "Average Monthly Residential Bill Increase" = expected increase in a typical Austin Energy residential customer's monthly electricity bill over time due to the additional net costs associated with the generation portfolio only  Based on the "Net Cost" of each portfolio  Does not account for any other new or required Austin Energy capital or O&M costs in the future 17 2035 Average Monthly Residential Bill Increase Austin Energy 2% Affordability Target is not adjusted for inflation. Monthly bill impact data provided in nominal dollars $80 $70 $60 $50 $40 $30 $20 $10 $- 15 16 17 14 2 (Reference) 2% Affordability 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 DISCLAIMER: These are representative results based on modeling for the 2035 Resource Generation Plan and are not projections of Austin Energy's future prices. The results are not inclusive of factors beyond the scope of this Resource Generation Plan modeling. 18 Electricity Burden  “Electricity Burden” is the percentage of a household’s monthly income that goes toward their electricity bill  A higher percentage of income dedicated to electricity costs indicates a higher “electricity burden” for that household  For this analysis Austin Energy estimates the electricity burden for a typical customer in its Customer Assistance Program (CAP) using the 2023 Federal Poverty Income guidelines as a reference for estimated annual income 19 2035 Electricity Burden 2035 Estimated Customer Assistance Program (CAP) Customer Electricity Burden (Avg of Scenarios) n e d r u B y t i c i r t c e E l 6.0% 5.0% 4.0% 3.0% 2.0% 1.0% 0.0% 14 15 Portfolio # 16 17 2035 Estimated CAP Customer Electricity Burden 2023 Estimated CAP Customer Electricity Burden 2023 State of Texas Average Low Income Customer Electricity Burden 20 Round II Modeling Portfolio Comparison – Liquidity Risk 21 Liquidity Risk  “Liquidity Risk” = Risk to Austin Energy of not having enough cash on-hand to settle financial account with ERCOT after an extreme event  Uses a modeling technique called “backcasting” to estimate how a portfolio of resources would have performed financially during an extreme winter & summer event  During an extreme event, ERCOT prices can spike – Austin Energy must purchase power from ERCOT to cover local load – if Austin Energy does not sell enough electricity at the same prices to cover expense, it must pay the difference to ERCOT immediately  Based on portfolio mix in 2035 22 Stress Test Results – Liquidity Risk Based on 2035 portfolio mix 1200 1000 800 M M $ 600 400 200 0 14 16 17 15 Portfolio # Uri Backcast 5k HCAP Total Liquidity Need ($MM) HCAP = ERCOT High System-wide Offer Cap Uri Backcast 5k HCAP + EPP Total Liquidity Need ($MM) EPP = ERCOT Emergency Pricing Program Summer 2023 Backcast Total Liquidity Need ($MM) 23 Stress Test Results – Total Liquidity Risk Based on 2035 portfolio mix Reference Portfolios M M $ 1800 1600 1400 1200 1000 800 600 400 200 0 1 2 3 4 5 6 7 11 12 13 14 15 16 17 8 9 Portfolio Number 10 Uri Backcast 5k HCAP Total Liquidity Need ($mm) Uri Backcast 5k HCAP + EPP Total Liquidity Need ($mm) Summer 2023 Backcast Total Liquidity Need ($mm) 24 Round II Modeling Portfolio Comparison – Reliability 25 Reliability Risk Hours  “Reliability Risk Hours” = total number of hours in a given year that the model predicts there will be increased risk of local outages  Local outages in this case are a result of not enough electricity physically available to meet Austin’s load  Can be caused by high local load, decrease in local power generation, decrease in import capacity, or a combination of these factors 26 Reliability Risk Hours – Ascend Portfolio 14 Portfolio 15 +250 MW import capacity 0 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 0 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 P5 MEAN P95 P5 MEAN P95 Portfolio 16 Portfolio 17 400 300 200 100 s r u o H k s i R y t i l i b a i l e R 400 300 200 100 s r u o H k s R y t i l i i b a i l e R 0 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 0 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 P5 MEAN P95 P5 MEAN P95 27 400 300 200 100 s r u o H k s R y t i l i i b a i l e R 400 300 200 100 s r u o H k s R y t i l i i b a i l e R  s r u o H k s R y t i l i i b a i l e R 500 400 300 200 100 0 s r u o H k s R y t i l i i b a i l e R 500 400 300 200 100 0 Reliability Risk Hours – UPLAN Normal Scenario 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 High Load Growth Scenario * 2,288 Risk Hrs (for P15 in 2035) 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 14 - High Load Forecast 15 - High Load Forecast 16 - High Load Forecast 17 - High Load Forecast 14 15 16 17 28 Peak Load is 21% Higher in 2035 in High Load Growth Scenario Round II Modeling Portfolio Comparison – Emissions 29 Modeled Austin Energy Stack CO2 Emissions By Year vs. Historical 7,000,000 6,000,000 5,000,000 4,000,000 3,000,000 2,000,000 2 O C s n o T c i r t e M 1,000,000 - Historical 14 15 16 17 30 Modeled Austin Energy Stack Emissions Total CO2 Emissions (Million Metric Tons) 2025-2035 Total NOx Emissions (Metric Tons) 2025-2035 6.1 4.6 5.2 4.9 621 476 542 511 x O N s n o T c i r t e M 700 600 500 400 300 200 100 - 14 15 16 17 14 15 16 17 Portfolio # Portfolio # 2 O C s n o T c i r t e M s n o i l l i M 7.0 6.0 5.0 4.0 3.0 2.0 1.0 - 31 Capacity Factor of Peakers - Ascend Capacity Factor (P14) Sand Hill Peakers Decker Peakers New NG Peakers Capacity Factor (P15) Sand Hill Peakers Decker Peakers Capacity Factor (P16) Sand Hill Peakers Decker Peakers Capacity Factor (P17) Sand Hill Peakers Decker Peakers 2025 10% 8% 0% 2025 9% 8% 2025 10% 8% 2025 10% 8% 2026 9% 8% 0% 2026 9% 8% 2026 9% 8% 2026 9% 8% 2027 8% 8% 8% 2027 8% 8% 2027 8% 8% 2027 8% 8% 2028 8% 8% 7% 2028 7% 8% 2028 7% 8% 2028 7% 8% 2030 2029 7% 7% 8% 8% 7% 16% 2029 7% 8% 2029 7% 8% 2029 7% 8% 2030 6% 8% 2030 6% 8% 2030 6% 8% 2031 6% 8% 9% 2031 4% 8% 2031 4% 8% 2031 4% 8% 2032 5% 8% 9% 2032 4% 8% 2032 4% 7% 2032 4% 7% 2033 5% 8% 8% 2033 3% 8% 2033 4% 8% 2033 4% 8% 2034 5% 8% 8% 2034 3% 8% 2034 3% 8% 2034 3% 8% 2035 4% 8% 5% 2035 0% 0% 2035 3% 7% 2035 3% 7% 32 Round II Modeling Portfolio Comparison - Summary 33 P12 vs. P15-17 (2025-2035) 1,482 10.9 10.9 10.8 10.6 4.3 4.6 5.2 4.9 371 15 12 104 16 104 17 12.0 10.0 8.0 6.0 4.0 2.0 0.0 1,600 1,400 1,200 1,000 800 600 400 200 0 I S R U O H K S R Y T I L I B A I L E R 34 12.0 10.0 8.0 6.0 4.0 2.0 0.0 416 9.8 10 P10 vs. P14 (2025-2035) 6.3 6.1 8.8 115 14 I S R U O H K S R Y T I L I B A I L E R 450 400 350 300 250 200 150 100 50 0 35 Round II Results Summary (2025-2035) 371 10.9 10.8 10.6 8.8 6.1 115 12.0 10.0 8.0 6.0 4.0 2.0 0.0 4.6 5.2 4.9 104 104 14 15 16 17 I S R U O H K S R Y T I L I B A I L E R 400 350 300 250 200 150 100 50 0 36 Key Insights from Modeling To Date and Next Steps 37 Transitioning to Plan Development Resource Modeling Resource Planning  How well do different resource mixes mitigate reliability, liquidity and load zone price separation risk?  What are the tradeoffs in reliability, cost, and emissions between different portfolio mixes?  What insights did we learn from the modeling process that should inform the plan?  What are the key characteristics from the modeled portfolios that mitigate risk and balance tradeoffs? 38 Key Insights from Modeling Results – Austin Energy • Addition of 250 MW import capacity beyond known transmission upgrades significantly reduces reliability risk and net costs • Loss of generation from Decker and Sand Hill significantly increases reliability risk and net costs • High levels of new energy efficiency, demand response, local solar and storage plus existing generation manage reliability and liquidity risk – at a high cost, and pace of adoption exceeds estimated feasibility • Model results are very sensitive to high load growth scenario • Local solar, storage and natural gas peaker units manage reliability while maintaining low overall capacity factor (<8% in 2035) – peakers used only when local demand and prices are high 39 Discussion & Collaboration ! What did you observe? What surprised you? What insights did you gain? What are the key characteristics from the modeled portfolios that you would like to see reflected in the plan? 40 EUC Office Hours • Tuesday, Oct. 22 3 p.m. – 4 p.m. • Wednesday, Oct. 23 8:30 a.m. – 10 a.m. • Thursday, Oct. 24 2:30 p.m. – 4 p.m. • Friday, Oct. 25 9:30 a.m. – 10:30 a.m. If you wish to attend and none of the above times work, please let us know so we can find a time to collaborate. Office Hours Objectives: • Review detailed results Office Hours Objectives: • Ask questions • Answer questions • Determine takeaways Share detail • • Refine portfolios • Discuss learnings By Wednesday, Oct. 30 – Seeking survey response from every Commissioner 41 Survey Questions Requested by Oct. 30 What key insights or lessons learned did you take away from the 2035 Resource Generation Plan modeling exercise? What are the most important characteristics from the portfolios we modeled that you would like to see reflected in the Resource, Generation and Climate Protection Plan to 2035? 42 ©Austin Energy. All rights reserved. Austin Energy and the Austin Energy logo and combinations thereof are trademarks of Austin Energy, the electric department of the City of Austin, Texas. Other names are for informational purposes only and may be trademarks of their respective owners.