Item 7 Backup_EUC Working Group Portfolios — original pdf

Backup

Item 7 Resource Generation Plan Update EUC Working Group Portfolios January 10, 2024 © Austin Energy EUC Working Group Portfolios Production Cost Modeling Key Results S. Babu Chakka Manager, Energy Market Analysis & Resource Planning 2 Portfolio A_2035 (Meet Load with Clean Energy, DR, EE & Batteries) EE DR Local Solar Batteries 5% Summer Peak Reduction by 2027 150 MW by 2027 Renewable Goals 65% by 2027 500 MW with 200 MW behind the meter by 2030 700 MW with 250 MW behind the meter by 2035 4 Hr: 100 MW Local +25 MW Nonlocal Co- located by 2027 200 MW = 100 MW Local + 100 MW Nonlocal Co-located by 2035 8 Hr: 100 MW Local +50 MW Nonlocal Co- located by 2027 200 MW = 100 MW Local + 100 MW Nonlocal Co-located by 2035 100 Hr: 10 MW Local by 2027 50 MW Local by 2030 100 MW Local by 2035 Convention Gen FPP retire in 2030 Natural Gas Plants retire in 2035 No Change to STP 10% Summer Peak Reduction by 2030 500 MW by 2035 70% by 2030 14% Summer Peak Reduction by 2035 80% by 2035 Note: • • • • • Energy Efficiency assumed existing programs and scaled to get the required the summer peak reduction 8 Hour Batteries were assumed for 4 to 12 Hour range 100 Hour Batteries were assumed instead of 72 Hour duration The technologies and the quantities of the options were modeled as per the request, but the feasibility and potential of these programs require detailed market research and market study. Decker GTs were retired in 2027 in Austin Energy portfolios where in these portfolios they are retired as per NG plants retirement timeline 3 Portfolio A_2030 (Meet Load with Clean Energy, DR, EE & Batteries) EE DR Local Solar Batteries 5% Summer Peak Reduction by 2027 150 MW by 2027 Renewable Goals 65% by 2027 350 MW with 150 MW behind the meter by 2027 500 MW with 200 MW behind the meter by 2030 4 Hr: 100 MW Local +25 MW Nonlocal Co- located by 2027 200 MW = 100 MW Local + 100 MW Nonlocal Co-located by 2030 8 Hr: 100 MW Local +50 MW Nonlocal Co- located by 2027 200 MW = 100 MW Local + 100 MW Nonlocal Co-located by 2030 Convention Gen FPP retire in 2030 Natural Gas Plants retire in 2030 10% Summer Peak Reduction by 2030 500 MW by 2030 80% by 2030 14% Summer Peak Reduction by 2035 700 MW with 250 MW behind the meter by 2035 100 Hr: 10 MW Local by 2027 100 MW Local by 2030 No Change to STP Note: • • • • • Energy Efficiency assumed existing programs and scaled to get the required the summer peak reduction 8 Hour Batteries were assumed for 4 to 12 Hour range 100 Hour Batteries were assumed instead of 72 Hour duration The technologies and the quantities of the options were modeled as per the request, but the feasibility and potential of these programs require detailed market research and market study. Decker GTs were retired in 2027 in Austin Energy portfolios where in these portfolios they are retired as per NG plants retirement timeline 4 Portfolio B_2035 (Meet Load with more storage, moderate DR/EE and moderate renewables) EE DR Local Solar Batteries 3% Summer Peak Reduction by 2027 100 MW by 2027 Renewable Goals 65% by 2027 475 MW with 200 MW behind the meter by 2030 4 Hr: 150 MW with 75 MW Local by 2027 300 MW with 150 MW Local + 25 MW Nonlocal Co-located by 2035 Convention Gen FPP retire in 2030 8% Summer Peak Reduction by 2035 200 MW by 2030 Add 200 MW after 2027 575 MW with 250 MW behind the meter by 2035 8 Hr: 50 MW by 2027 100 MW with 25 MW Nonlocal Co- located by 2035 Natural Gas Plants retire in 2035 300 MW by 2035 100 Hr: 100 MW Local by 2027 200 MW Local by 2035 No Change to STP Note: • • • • • Energy Efficiency assumed existing programs and scaled to get the required the summer peak reduction 8 Hour Batteries were assumed for 4 to 12 Hour range 100 Hour Batteries were assumed instead of 72 Hour duration The technologies and the quantities of the options were modeled as per the request, but the feasibility and potential of these programs require detailed market research and market study. Decker GTs were retired in 2027 in Austin Energy portfolios where in these portfolios they are retired as per NG plants retirement timeline 5 Portfolio B_2030 (Meet Load with more storage, moderate DR/EE and moderate renewables) EE DR Local Solar Batteries 3% Summer Peak Reduction by 2027 100 MW by 2027 Renewable Goals 65% by 2027 475 MW with 200 MW behind the meter by 2027 4 Hr: 150 MW with 50 MW Local by 2027 300 MW with 100 MW Local + 25 MW Nonlocal Co-located by 2030 Convention Gen FPP retire in 2030 8% Summer Peak Reduction by 2030 300 MW by 2030 Add 200 MW after 2027 575 MW with 250 MW behind the meter by 2030 8 Hr: 50 MW by 2027 100 MW with 25 MW Nonlocal Co- located by 2030 Natural Gas Plants retire in 2030 100 Hr: 100 MW Local by 2027 200 MW Local by 2030 No Change to STP Note: • • • • • Energy Efficiency assumed existing programs and scaled to get the required the summer peak reduction 8 Hour Batteries were assumed for 4 to 12 Hour range 100 Hour Batteries were assumed instead of 72 Hour duration The technologies and the quantities of the options were modeled as per the request, but the feasibility and potential of these programs require detailed market research and market study. Decker GTs were retired in 2027 in Austin Energy portfolios where in these portfolios they are retired as per NG plants retirement timeline 6 Wind Addition in MW Annual Additions Portfolio A_2035 Portfolio A_2030 Portfolio B_2035 Portfolio B_2030 2025 0 0 0 0 2026 0 0 0 0 2027 0 0 0 0 2028 50 300 100 100 2029 50 150 0 0 2030 50 200 100 100 2031 200 50 0 0 2032 200 50 0 0 2033 150 50 0 0 2034 150 50 0 0 2035 100 100 0 0 Total Battery Addition in MW (4 Hour duration) 2027 2026 Battery Addition in MW (8 Hour duration) 2027 2026 2028 2029 2030 2031 2032 2033 2034 2035 Total Portfolio A_2035 Portfolio A_2030 Portfolio B_2035 Portfolio B_2030 Portfolio A_2035 Portfolio A_2030 Portfolio B_2035 Portfolio B_2030 Portfolio A_2035 Portfolio A_2030 Portfolio B_2035 Portfolio B_2030 2025 60 60 50 80 2025 70 70 10 30 2025 4 4 50 50 2028 2029 2030 2031 2032 2033 2034 2035 Total 35 35 50 35 45 45 20 10 30 30 50 35 35 35 20 10 5 15 45 70 10 10 30 35 10 40 20 40 10 20 5 10 4 4 25 25 2 2 25 25 10 30 20 50 10 30 20 25 10 20 15 40 10 20 5 5 20 30 10 25 10 0 15 0 10 0 5 0 10 0 10 0 10 0 15 0 10 0 5 0 10 0 10 0 10 0 15 0 0 0 0 0 10 0 10 0 10 0 15 0 0 0 0 0 10 0 10 0 10 0 10 0 0 0 0 0 10 0 10 0 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Total Battery Addition in MW (100 Hour duration) 950 950 200 200 200 200 300 300 200 200 100 100 100 100 200 200 *Utility Scale Solar is included in the base case to achieve 65% renewable target 7 Key Assumptions 8 Demand Response (in $ millions) DR Portfolio A-2035 Portfolio A-2030 Portfolio B-2035 Portfolio B-2030 2025 $6 $11 $6 $8 2026 $10 $18 $7 $12 2027 $19 $30 $12 $19 2028 $25 $76 $15 $38 2029 $30 $95 $20 $48 2030 $39 $143 $26 $74 2031 $44 $100 $29 $60 2032 $52 $100 $32 $60 2033 $67 $113 $40 $68 2034 $77 $113 $43 $68 2035 $76 $113 $46 $68 *These costs are in addition to the existing budget and will result in increase Community Benefit Charges 500 MW of DR is comprised of 200 MW of Behavioral DR and the balance is by energy storage located at the customer site Total $445 $910 $275 $523 9 Customer Investment Needed for DR Customer Site Batteries Portfolio A-2035 Portfolio A-2030 Portfolio B-2035 Portfolio B-2030 2025 $7 $7 $5 $3 2026 $6 $4 $3 $2 2027 $7 $3 $3 $2 2028 $8 $11 $3 $3 2029 $7 $12 $2 $4 2030 $7 $8 $3 $3 2031 $6 $2 $3 $2 2032 $8 $2 $2 $1 2033 $5 $1 $1 $1 2034 $7 $1 $1 $0 2035 $7 $1 $1 $0 Total $74 $52 $28 $21 10 Energy Efficiency (in $ millions) EE Portfolio A Portfolio B-2035 Portfolio B-2030 2026 $33 $16 $14 2027 $38 $19 $20 2028 $39 $25 $30 2029 $28 $23 $32 2030 $21 $19 $30 2031 $25 $16 $6 2032 $21 $12 $1 2033 $21 $7 $1 2034 $25 $5 $2 2035 $21 $1 $1 Total $271 $143 $138 These costs are in addition to the existing budget and will result in increase Community Benefit Charges The costs are for summer peak reduction targets. The cost will be significantly higher (expensive) if winter programs are considered 11 2025 $1 $0 $1 • • Key Assumptions: Technology Costs Technology Wind Local Solar - Residential Local Solar - Community Battery Storage (4 hour duration) Battery Storage (8 hour duration) Battery Storage (100 hour duration) Capital Cost ($/kW) 1,848-1,884 0 0 1,133 - 1,204 1,633 -2,352 1,717-2,584 Variable O&M ($/MWh) 99 92 0 0 0 Note: From our understanding, 100-hour duration is still a concept, and the first fully operational 100-hour duration is expected to be 2026 – 2027 timeframe Fixed O&M ($/kW-yr) 22 - 24 0 0 14 - 16 14 - 16 14 - 24 12 Key Assumptions: Fuel Price Projections *Model assumes Fayette Power Project retirement in 2030 13 Annual Cost (Fixed Cost in $Million) Total Cost for 10 years = $2.097 Billion Total Cost for 10 years = $2.862 Billion Note: Solar, Wind and Batteries are assumed to be AE Built and Owned EE and DR Cost are for the incentives, annual reimbursement and maintenance Behind the meter Solar and Community Solar is recovered through the PSA 14 Annual Cost (Fixed Cost in $Million) Total Cost for 10 years = $1.785 Billion Total Cost for 10 years = $2.11 Billion Note: Solar, Wind and Batteries are assumed to be AE Built and Owned EE and DR Cost are for the incentives, annual reimbursement and maintenance Behind the meter Solar and Community Solar is recovered through the PSA 15 Result Summaries 16 Results Summary – The Framework r a e Y r e p n o i l l i M $ n i s r e m o t s u C o t t s o C d e z i l e v e L $2000 $1800 $1600 $1400 $1200 $1000 $800 $600 $400 $200 $0 $ total $ risk $ risk $ risk $ cost Technology Portfolio Quantifies the additional annual risk (cost) to customers due to market rule changes, based on portfolio’s Effective Load Carrying Capability (ELCC) Quantifies the additional annual risk (cost) to customers for a particular technology portfolio due to local congestion Quantifies the additional annual risk (cost) to customers for a particular technology portfolio under extreme weather conditions in any given year Quantifies the annual levelized cost to customers for a particular technology portfolio under normal conditions This includes the capital and O&M costs of new supply resources and the removal of O&M of existing supply resources when they are retired For comparison purposes, the current power supply cost to customers is approximately $585 million per year 17 Results Summary – Portfolio A_2035 Key Assumptions • Includes technologies as laid out by EUC WG • All 1400 MW of existing generation retired at end of 2035, which means they are available in the Extreme Weather analysis year • Assumes EE and behind the meter solar is available when the grid needs them the most Key Takeaways • The costs and the risk will be higher if EE/DR do not materialize • It may not be feasible to obtain and host these large quantities of local solar and local storage • Modeled EE and Demand Response quantities may not be feasible retired* • Significant risk will exist in 2036, the year after generation is This portfolio has risk due to ERCOT market rule changes of $73 million per year Local congestion costs are mitigated because the supply is located in Austin Energy’s load zone Under extreme weather conditions, this portfolio has an additional risk of $206 million per year This portfolio has a high levelized cost of $800 million *As seen in 2030 portfolios, which do not include existing generation in the Extreme Weather analysis year 18 Results Summary – Portfolio A_2030 Key Assumptions • Includes technologies as laid out by EUC WG • All 1400 MW of existing generation retired at end of 2030 • Extreme weather analysis year is 2035, so no existing generation included • Assumes EE and behind the meter solar is available when the grid needs them the most Key Takeaways the base case • The portfolio is costly for customers, but less costly than • It does not mitigate risks during extreme weather • The costs and the risk will be higher if EE/DR do not materialize be feasible • It may not be feasible to obtain and host these large quantities of local solar and local storage • Modeled EE and Demand Response quantities may not This portfolio is capacity deficient in terms of Effective Load Carrying Capacity, so it includes $143 million of additional risk per year under ERCOT market rule changes This portfolio has a local congestion risk of $9 million Under extreme weather conditions, this portfolio has an additional risk of $540 million per year This portfolio has a high levelized cost of $931 million 19 Results Summary – Portfolio B_2035 Key Assumptions • Includes technologies as laid out by EUC WG • All 1400 MW of existing generation retired at end of 2035, which means they are available in the Extreme Weather analysis year • Assumes EE and behind the meter solar is available when the grid needs them the most Key Takeaways materialize • The costs and the risk will be higher if EE/DR do not • It may not be feasible to obtain and host these large quantities of local solar and local storage • Modeled EE and Demand Response quantities may not be feasible • Significant risk will exist in 2036, the year after generation is retired* This portfolio has risk due to ERCOT market rule changes of $79 million per year Local congestion is nearly gone because the supply is located in Austin Energy’s load zone Under extreme weather conditions, this portfolio has an additional risk of $227 million per year This portfolio has a high levelized cost of $819 million *As seen in 2030 portfolios, which do not include existing generation in the Extreme Weather analysis year 20 Results Summary – Portfolio B_2030 Key Assumptions • Includes technologies as laid out by EUC WG • All 1400 MW of existing generation retired at end of 2030 • Extreme weather analysis year is 2035, so no existing generation included • Assumes EE and behind the meter solar is available when the grid needs them the most Key Takeaways • The portfolio is the most costly and risky for customers, even higher than the base case • It does not mitigate risks during extreme weather, and may include bankruptcy risk • The costs and the risk will be higher if EE/DR do not materialize • It does not perform well under ERCOT market rule changes and presents local congestion risk • It may not be feasible to obtain and host these large quantities of local solar and local storage • Modeled EE and Demand Response quantities may not be feasible This portfolio is capacity deficient in terms of Effective Load Carrying Capacity, so it includes $151 million of additional risk per year under ERCOT market rule changes This portfolio has a local congestion risk of $50 million Under extreme weather conditions, this portfolio has an additional risk of $758 million per year This portfolio has a high levelized cost of $946 million 21 Criteria Definitions Affordable • Green/Yes- affordability impact does not exceed a 2% increase threshold • Red/No- affordability impact exceeds the 2% increase threshold Total Cost/Risk (in $millions) • Green- is the cost : 0 to 7.5% Increase from the lowest risk in that scenario • Yellow- is the cost :7.5% to 20% Increase from the lowest risk in that scenario • Red- is the cost: >20% Increase from the lowest risk in that scenario Levelized cost (in $millions) • Green- is the cost : 0 to 7.5% Increase from the lowest risk in that scenario • Yellow- is the cost :7.5% to 20% Increase from the lowest risk in that scenario • Red- is the cost: >20% Increase from the lowest risk in that scenario 22 Criteria Definitions Extreme Weather Risk (in $millions) • Green- is the cost : 0 to 7.5% Increase from the lowest risk in that scenario • Yellow- is the cost :7.5% to 20% Increase from the lowest risk in that scenario • Red- is the cost: >20% Increase from the lowest risk in that scenario Local Congestion Risk (in $millions) • Green- is the cost : 0 to 7.5% Increase from the lowest risk in that scenario • Yellow- is the cost :7.5% to 20% Increase from the lowest risk in that scenario • Red- is the cost: >20% Increase from the lowest risk in that scenario ERCOT Market Change Risk (in $millions) • Green- is the cost : 0 to 7.5% Increase from the lowest risk in that scenario • Yellow- is the cost :7.5% to 20% Increase from the lowest risk in that scenario • Red- is the cost: >20% Increase from the lowest risk in that scenario 23 Working Group Summary Matrix ID Technology Portfolio WG1 Portfolio A_2035 WG2 Portfolio A_2030 WG3 Portfolio B_2035 WG4 Portfolio B_2030 Mapping to 2030 Plan Objectives: Carbon Free by 2035 Renewable Goals Affordable Total Cost/Risk (in $Million) Levelized Cost (in $Million) Extreme Weather Risk (in $Million) Local Congestion Risk (in $Million) ERCOT Market Rule Change Risk (in $Million) No No No No $1,079 $1,624 $1,130 $1,904 $800 $931 $819 $946 $206 $540 $227 $758 A CS A CS A CS R A CS R CS R CS Demand Side Mgmt Goals Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes ES Environmental Sustainability Affordability Cost Stability $0 $9 $4 $50 A Reliability Affordability Cost Stability $73 $143 $79 $151 A 24 © 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. Summary Matrix ID Technology Portfolio 1 CF_2035 (Current 2030 Plan or Base Case) 2 CF_2035 without REACH 3 CF_2035 + LSOL 4 CF_2035 + LDST 5 CF_2035 + HCCC 6 CF_2035 + LSOL + HCCC 7 CF_2035 + LDST + HCCC 8 CF_2035 + LSOL + LLDST + DST 9 CF_2035 + LLDST + DST + HCCC 10 CF_2035 + LSOL + LLDST + DST + DSM 11 CF_2035 + LSOL + LLDST + DST + HCCC Mapping to 2030 Plan Objectives: Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Carbon Free by 2035 Renewable Goals Demand Side Mgmt Goals Affordable Total Cost/Risk (in $Million) Levelized Cost (in $Million) Extreme Weather Risk (in $Million) Local Congestion Risk (in $Million) ERCOT Market Rule Change Risk (in $Million) Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes No No No No Yes Yes Yes No Yes No Yes $1,843 $1,836 $1,517 $1,668 $838 $954 $902 $1,544 $1,003 $1,582 $1,158 $899 $892 $933 $933 $599 $630 $643 $944 $651 $907 $757 $477 $477 $417 $424 $161 $231 $185 $448 $264 $523 $304 $294 $294 $226 $2 $3 $1 ($3) ($1) $2 $5 ($4) $173 $173 $164 $85 $75 $92 $77 $153 $86 $146 $102 ES Environmental Sustainability A CS A CS A CS R A CS R A CS R A CS R Affordability Cost Stability Reliability Affordability Cost Stability 26