City Council and Authorities Concurrent
December 5, 2023

3. Effective date: This resolution shall be effective immediately.

I HEREBY CERTIFY THE FOREGOING TO BE A TRUE COPY OF A RESOLUTION PASSED

AND ADOPTED BY THE CITY OF SANTA CLARA, CALIFORNIA, AT A REGULAR MEETING THEREOF HELD ON THE 26TH DAY OF OCTOBER, 2021, BY THE FOLLOWING VOTE:

AYES: COUNCILORS:

NOES: COUNCILORS:

ABSENT: COUNCILORS:

ABSTAINED: COUNCILORS:

Attachments incorporated by reference:

Becker, Chahal, Hardy, Jain, Park, and Watanabe,
and Mayor Gillmor
None
None
None ~
ATTEST NORA PIMENTEL, MMC ✓ ASSISTANT CITY CLERK

CITY OF SANTA CLARA

1. 2022 Board of Library Trustees calendar of meetings
Resolution/ Approving the 2022 Board of Library Trustees Calendar of Meetings Rev: 11 /22/17

Board of Library Trustees
2024 Meeting Calendar
All meetings start at 6:00 PM unless otherwise noted
Date Location
February 5, 2024 Margie Edinger Room, Central Park Library 2635 Homestead Rd, Santa Clara, CA 95051
March 4, 2024 Margie Edinger Room, Central Park Library 2635 Homestead Rd, Santa Clara, CA 95051
April 1, 2024 Program Room, Northside Branch Library
695 Moreland Way, Santa Clara, CA 95054
May 6, 2024 Margie Edinger Room, Central Park Library
2635 Homestead Rd, Santa Clara, CA 95051
June 3, 2024 Community Room, Mission Branch Library
1098 Lexington St, Santa Clara, CA 95050
August 5, 2024 Margie Edinger Room, Central Park Library 2635 Homestead Rd, Santa Clara, CA 95051
September 16, 2024
October 7, 2024
November 4, 2024
December 2, 2024
Board of Library Trustees
Margie Edinger Room, Central Park Library
2635 Homestead Rd, Santa Clara, CA 95051
Program Room, Northside Branch Library
695 Moreland Way, Santa Clara, CA 95054
Margie Edinger Room, Central Park Library
2635 Homestead Rd, Santa Clara, CA 95051
Community Room, Mission Branch Library
1098 Lexington St, Santa Clara, CA 95050
City of
Santa Clara
The Center of What's Possible
Resolution/Board of Library Trustees Meetings 2024 Page 1 of 2 Rev: 8/29/2023
RESOLUTION NO. _____

A RESOLUTION OF THE CITY OF SANTA CLARA, CALIFORNIA
AMENDING RESOLUTION NO. 21-9016, APPROVING THE 2024

BOARD OF LIBRARY TRUSTEES CALENDAR OF MEETINGS,

AND SETTING THE NUMBER OF REGULAR BOARD OF

LIBRARY TRUSTEES MEETINGS
WHEREAS, Section 2.120.030 of the Santa Clara city Code (“SCCC”) requires City boards and commissions to hold regular meetings at the times and on the days indicated by resolution of the Council;
WHEREAS, Resolution 21-9016 adopted by the City Council on October 26, 2021, states that the Board of Library Trustees shall hold its meetings on the first Monday of every month with the exception of January and July at 6:00 p.m. subject to cancellation at the discretion of the City Manager for agenda management purposes. Should the first Monday fall on a City holiday, the meeting would be held on the next non-holiday Monday; and, WHEREAS, the Board of Library Trustees, at its November 6, 2023 meeting recommended a new meeting schedule for 2024 which proposes ten (10) regular meetings and a start time of 6:00 p.m.

NOW THEREFORE, BE IT RESOLVED BY THE CITY OF SANTA CLARA AS FOLLOWS:

1. That the City of Santa Clara hereby finds that the above Recitals are true and correct and by the reference makes them a part thereof.

2. That the City Council hereby approves setting the Board of Library Trustees regular meeting start time at 6:00 p.m., and establishes ten (10) meetings per year, to meet monthly except January and July, set on every first Monday of each month, beginning in February, as set forth in the attached Board of Library Trustees 2024 Meeting Dates document, which meetings may be cancelled at the discretion of the City Manager based upon best practices for agenda management. That should the first Monday fall on a City holiday, the meeting would be held on the next non-holiday Monday.

3. Effective date. This resolution shall become effective immediately.

Resolution/Board of Library Trustees Meetings 2024 Page 2 of 2 Rev: 8/29/2023

I HEREBY CERTIFY THE FOREGOING TO BE A TRUE COPY OF A RESOLUTION PASSED

AND ADOPTED BY THE CITY OF SANTA CLARA, CALIFORNIA, AT A REGULAR MEETING THEREOF HELD ON THE ___ DAY OF _________, 2023, BY THE FOLLOWING VOTE:

AYES: COUNCILORS:

NOES: COUNCILORS:

ABSENT: COUNCILORS:

ABSTAINED: COUNCILORS:

ATTEST: ______________________________

NORA PIMENTEL, MMC

ASSISTANT CITY CLERK

CITY OF SANTA CLARA
Attachments incorporated by reference:

1. 2024 Board of Library Trustees Meeting Calendar
Board of Library Trustees
2024 Meeting Calendar
All meetings start at 6:00 PM unless otherwise noted
Date Location
February 5, 2024 Margie Edinger Room, Central Park Library 2635 Homestead Rd, Santa Clara, CA 95051
March 4, 2024 Margie Edinger Room, Central Park Library 2635 Homestead Rd, Santa Clara, CA 95051
April 1, 2024 Program Room, Northside Branch Library
695 Moreland Way, Santa Clara, CA 95054
May 6, 2024 Margie Edinger Room, Central Park Library
2635 Homestead Rd, Santa Clara, CA 95051
June 3, 2024 Community Room, Mission Branch Library
1098 Lexington St, Santa Clara, CA 95050
August 5, 2024 Margie Edinger Room, Central Park Library 2635 Homestead Rd, Santa Clara, CA 95051
September 16, 2024
October 7, 2024
November 4, 2024
December 2, 2024
Board of Library Trustees
Margie Edinger Room, Central Park Library
2635 Homestead Rd, Santa Clara, CA 95051
Program Room, Northside Branch Library
695 Moreland Way, Santa Clara, CA 95054
Margie Edinger Room, Central Park Library
2635 Homestead Rd, Santa Clara, CA 95051
Community Room, Mission Branch Library
1098 Lexington St, Santa Clara, CA 95050
City of
Santa Clara
The Center of What's Possible
City of Santa Clara
Agenda Report
1500 Warburton Avenue
Santa Clara, CA 95050
santaclaraca.gov
@SantaClaraCity
23-1046 Agenda Date: 12/5/2023

REPORT TO COUNCIL

SUBJECT
Action on Adoption of Silicon Valley Power’s 2023 Integrated Resources Plan

BACKGROUND
Senate Bill 350 (Chapter 547, Statutes of 2015) (SB 350) requires publicly owned utilities (POUs) with an average annual load greater than 700 gigawatt-hours, to adopt an Integrated Resource Plan (IRP) and update the plan at least once every five years. POUs must then submit their IRP to the California Energy Commission (CEC) for their review. The CEC is required to review the IRPs for consistency with Public Utilities Code Section 9621 and recommend corrections to any deficiencies in the plans. The CEC formally adopted guidelines in August 2017 and has amended them several times with the latest revision occurring in October 2018. Silicon Valley Power’s first IRP was approved by the City Council on November 27, 2018, which was submitted to the California Energy Commission (CEC) on April 26, 2019.

IRPs are electric system planning documents that lay out a POU’s resource needs, policy goals, physical and operational constraints, and general priorities, and proposed resource choices, including customer-side preferred resources. These plans help the CEC evaluate how utilities have chosen to meet greenhouse gas (GHG) emission reduction targets and other policy goals outlined in SB 350, including but not limited to:
· Reductions in electricity sector GHG emissions commensurate with economy-wide reductions of 40 percent below 1990 levels by 2030;
· A Renewables Portfolio Standard of 60 percent by 2030; and · Energy efficiency, energy storage, and vehicle electrification policy goals.

SVP’s IRP must be designed to comply with GHG emissions reduction targets established by the California Air Resources Board (CARB) for the electricity sector, in coordination with the California Public Utilities Commission (CPUC) and the CEC. On September 10, 2018, SB 100 was signed into law, increasing the renewable energy resource procurement requirement from 50 percent to 60 percent by 2030.

The law further requires that SVP’s IRP consider the following to ensure SVP meets its energy and reliability needs: existing renewable generation, grid operational efficiencies, energy storage, and distributed energy resources, including energy efficiency. Excluding demand met by variable renewable generation, SVP must also consider how it will meet its peak electric load demands, while reducing the need for new generation and transmission resources.

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23-1046 Agenda Date: 12/5/2023

DISCUSSION
SVP kicked off its IRP development at the beginning of 2023. Through an RFP process, SVP selected Energy and Environmental Economics, Inc. (E3) to help build a model and run scenarios to show how SVP could meet its resources needs with different resource choices. E3 is in the process of finalizing the IRP report, a draft in substantial form is attached to this report.

Outreach
SVP held a public meeting to introduce SVP’s IRP. There were approximately 15 people in attendance at the meeting, including residential customers and a data center customer. In addition, SVP released a survey to gather community feedback on the IRP for a 6-week period. SVP promoted the survey during the September Arts and Wine Festival and through email and social media.

Based on 152 customer responses, the survey results revealed the following electric service priorities (in order of highest preference):
· High reliability (keeping the lights on and avoiding blackouts) · Minimizing Environmental Impacts
· Affordable Rates
· Quality of Customer Service
The survey also revealed the following preferences in response to the question how much more would you be willing to pay to reach clean energy goals faster:
· 37% of the respondents were willing to pay 25% more
· 23% of the respondents were willing to pay 10% more
· 29% of the respondents were not willing to pay more
IRP Highlights
In the IRP, SVP presents three resource portfolios developed using least cost optimization, all of which meet or exceed the State’s emission and reliability requirements. · The first portfolio meets CARB’s base targets for SVP and the 60% renewable energy target in 2030 of SB 100, using mature renewable technologies (those commercially available today). · The second portfolio: (1) moves forward the Senate Bill 100 renewable energy and zerocarbon generation targets for 2045 to 2035; (2) requires a minimum of 70% carbon-free energy (60% renewable) in 2030; (3) requires 100% carbon free by 2035; and (4) is limited to mature technologies.
· The third portfolio achieves a zero-carbon emissions portfolio across all hours of the year and explores the use of emerging technologies (such as biogas, hydrogen, and natural gas with carbon capture and storage) to achieve that goal.

The results show that in 2026, SVP will need over 350 MWs of new battery and renewable energy capacity to cover projected load growth, and by 2035 this number will increase to over 1,100 MWs.

In 2035, the IRP also assumes that SVP’s existing fleet of natural gas power plants will be running on either renewable natural gas or green hydrogen.

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23-1046 Agenda Date: 12/5/2023
The challenges of meeting the IRP’s goals include:
· Meeting our SVP’s load growth and securing sufficient clean resources to meet system load at all hours.
· Clean resources that can generate electricity across the entire day will be critical for SVP’s load shape and future system needs.
· Competition for limited resources in California can add difficulties for SVP to procure costeffective resources. · Uncertainties in long-term cost forecast.
· Achieving zero emissions in every hour will likely require a combination of commercially available resources and new emerging technologies to be cost-effective and affordable. There are large uncertainties and risks in emerging technologies. · SVP’s transmission capabilities with the CAISO can have an impact on how much emissions reduction SVP can achieve.

SB 350 requires SVP’s governing board, the Santa Clara City Council, to adopt the IRP in substantial form by January 1, 2024. Because the final IRP submittal requires numbers and information from calendar year 2023 to be included in the submission, the final IRP will be submitted to the CEC by April 30, 2024, with the appropriate updates and incorporating any final City Council feedback.

ENVIRONMENTAL REVIEW
The action being considered does not constitute a “project” within the meaning of the California Environmental Quality Act (“CEQA”) pursuant to section 15378(b)(5) in that the IRP is a planning document required to comply with state law and therefore an administrative activity that will not result in direct or indirect physical changes in the environment.

FISCAL IMPACT
There is no fiscal impact associated with the approval of Silicon Valley Power’s 2023 Integrated Resources Plan.

COORDINATION
This report has been coordinated with the Finance Department and City Attorney’s Office.

PUBLIC CONTACT
Public contact was made by posting the Council agenda on the City’s official-notice bulletin board outside City Hall Council Chambers. A complete agenda packet is available on the City’s website and in the City Clerk’s Office at least 72 hours prior to a Regular Meeting and 24 hours prior to a Special Meeting. A hard copy of any agenda report may be requested by contacting the City Clerk’s Office at (408) 615-2220, email [email protected] <mailto:[email protected]> or at the public information desk at any City of Santa Clara public library.

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23-1046 Agenda Date: 12/5/2023

RECOMMENDATION

1. Adopt Silicon Valley Power’s 2023 Integrated Resources Plan in substantially the form attached to this Report to Council; and

2. Authorize the City Manager or designee to finalize the Integrated Resources Plan with any updates to incorporate 2023 information and numbers, address City Council comments, additional feedback, and non-substantive edits and submit the final plan to the California Energy Commission prior to April 30, 2024, and to take any actions as necessary to administer and implement the Integrated Resources Plan, including amending the plan as may be required by the California Energy Commission.

Reviewed by: Manuel Pineda, Chief Electric Utility Officer Approved by: Jovan D. Grogan, City Manager

ATTACHMENTS

1. Silicon Valley Power’s 2023 Integrated Resource Plan in Substantive Form City of Santa Clara Page 4 of 4 Printed on 12/1/2023
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2023 Integrated Resource Plan
Silicon Valley Power (SVP)
DRAFT 2023

415.391.5100 | 44 Montgomery Street, Suite 1500, San Francisco, CA 94104 | www.ethree.com Respectfully Submitted,
Nathan Lee
Energy and Environmental Economics, Inc. (E3)
44 Montgomery Street, Suite 1500
San Francisco, CA 94104
© DRAFT 2023 Energy & Environmental Economics, Inc.
415.391.5100 | 44 Montgomery Street, Suite 1500, San Francisco, CA 94104 | www.ethree.com Table of Contents
Table of Figures _______________________________________________________________ i Acronym Definitions __________________________________________________________ v

1. Executive Summary ______________________________________________________ 1

2. Introduction ____________________________________________________________ 7

2.1. Silicon Valley Power ___________________________________________________________ 7

2.2. State Laws, Policy, and Regulations_______________________________________________ 7

2.3. Relevant State Legislation and Executive Orders ____________________________________ 8

2.4. Federal Legislation ___________________________________________________________ 10

2.5. CEC IRP Guidelines ___________________________________________________________ 10

2.6. Public Stakeholder Engagement_________________________________________________ 14

2.7. The Integrated Resource Planning Process ________________________________________ 15

3. Energy and Demand Forecast _____________________________________________ 17

3.1. Historic Energy Use and Demand________________________________________________ 17

3.2. Demand Forecast Methodology and Assumptions __________________________________ 17

4. Existing and Planned System and Resources _________________________________ 21

4.1. Existing Resources and System Description _______________________________________ 21

4.2. Existing and Planned Resources_________________________________________________ 22

4.3. Description of Santa Clara Owned and Contracted Resources_________________________ 26

4.4. Northern California Power Agency (NCPA) Resources _______________________________ 29

4.5. M‐S‐R Resources _____________________________________________________________ 31

4.6. Renewable Energy Strategy ____________________________________________________ 31

4.7. Transmission and Distribution System Assets and Adequacy _________________________ 32

4.8. Natural Gas Commodity, Transportation and Storage _______________________________ 34

4.9. Wholesale Energy Trading _____________________________________________________ 35

5. Customer Programs, Energy Efficiency and Demand Response Resources__________ 36

5.1. Energy Efficiency Program Background ___________________________________________ 36

5.2. Current Energy Efficiency and Building Electrification Initiatives ______________________ 37

5.3. Storage_____________________________________________________________________ 44 415.391.5100 | 44 Montgomery Street, Suite 1500, San Francisco, CA 94104 | www.ethree.com

5.4. Transportation Electrification __________________________________________________ 48

6. SVP System Modeling Approach ___________________________________________ 60

6.1. PLEXOS LT Overview __________________________________________________________ 60

6.2. Objective Function ___________________________________________________________ 60

6.3. SVP System Representation ____________________________________________________ 61

6.4. Model Constraints____________________________________________________________ 63

6.5. Capacity Expansion Model Configuration _________________________________________ 71

6.6. Scenarios and Sensitivities Considered ___________________________________________ 72

6.7. Model Inputs ________________________________________________________________ 73

6.8. Model Outputs ______________________________________________________________ 75

7. Portfolio Expansion Resource Options ______________________________________ 76

7.1. Candidate Resource Assumptions _______________________________________________ 76

7.2. Candidate Resource Costs _____________________________________________________ 82

7.3. Reliability Requirement Assumptions ____________________________________________ 86

7.4. Fuel Prices __________________________________________________________________ 86

7.5. Transmission ________________________________________________________________ 88

8. Results and Discussion ___________________________________________________ 90

8.1. Scenario 1: Base SB 100 _______________________________________________________ 90

8.2. Scenario 2: Accelerated SB 100 _________________________________________________ 96

8.3. Scenario 3: Zero Emissions with Emerging Technology _____________________________ 101

8.4. Scenario Comparison ________________________________________________________ 107

8.5. Sensitivity: Geothermal Limitations and Hydrogen Challenges _______________________ 111

8.6. Challenges Ahead to Meet IRP Goals____________________________________________ 114

8.7. Potential Impacts on Retail Rates ______________________________________________ 116

8.8. Consideration of Localized Air Pollutants and Disadvantaged Communities ____________ 117

9. Conclusions___________________________________________________________ 120 Appendix A. SVP Community Survey Summary ________________________________ 121 Appendix B. Energy Demand _______________________________________________ 129 A.1. Energy Use and Demand______________________________________________________ 129 Appendix C. Hydrogen Price Forecasts _______________________________________ 133 Appendix D. Standardized Tables ___________________________________________ 135 415.391.5100 | 44 Montgomery Street, Suite 1500, San Francisco, CA 94104 | www.ethree.com i Table of Figures
Figure ES‐1. Silicon Valley Power IRP Scenarios............................................................................................ 1 Figure ES‐2. Base Scenario Cumulative New Build Capacity......................................................................... 2 Figure ES‐3. Scenario Comparison – 2035 Total Capacity............................................................................. 3 Figure ES‐4. Scenario Comparison – 2035 Annual Cost Relative to Base Scenario (2022 $MM) .................4 Figure 1. Summary of CEC IRP Filing Requirements.................................................................................... 12 Figure 2. Core Objectives of SVP’s IRP ........................................................................................................ 16 Figure 3. SVP Customer Mix by Retail Sales in 2022................................................................................... 17 Figure 4. SVP Baseline Energy Demand Forecast (GWh) ............................................................................ 18 Figure 5. Reference Scenario Annual Electricity Demand and Demand Modifier Impacts (GWh).............18 Figure 6: Total Annual Electricity Demand ‐ Reference Scenario ............................................................... 19 Figure 7. Hourly Demand Profile Components........................................................................................... 20 Figure 8. SVP Generation Portfolio Mix by Technology, 2022.................................................................... 22 Figure 9. SVP Existing and Planned Resource Portfolio, 2024‐2035........................................................... 23 Figure 10. SVP’s Resource Portfolio in 2023 ............................................................................................... 23 Figure 11. SVP’s Current Power Resource Locations (Owned and Contracted) ......................................... 25 Figure 12. SVP’s Planned Resource Additions in Future Years ................................................................... 25 Figure 13. Planned Resource Retirements.................................................................................................. 26 Figure 14. Current approved SVP Transmission Projects............................................................................ 34 Figure 15. Forecasted Energy Efficiency Potential...................................................................................... 37 Figure 16. Lithium Price ($/lbs) 2019‐2023................................................................................................. 45 Figure 17. New Zero Emission Vehicle Sales by year: Santa Clara.............................................................. 51 Figure 18. CVRP Rebate Dollars in SVP Service Territory by year............................................................... 52 Figure 19. Cumulative SVP ZEV Rebates by ZEV Type, 2011‐2018 ............................................................. 52 Figure 20. CEC Projected EV Adoption (cumulative)................................................................................... 53 Figure 21. Forecasted Plug‐in Vehicles and Charging Requirements, Cumulative – Santa Clara ...............54 Figure 22. Current Charger Port Installations by Type and Ownership ...................................................... 54 415.391.5100 | 44 Montgomery Street, Suite 1500, San Francisco, CA 94104 | www.ethree.com ii Figure 23. Map of PEV known Chargers within Santa Clara ....................................................................... 55 Figure 24. EV Charger Distributions by Santa Clara Zip Codes ................................................................... 56 Figure 25. Utility Risks and Opportunities from PEV Adoption .................................................................. 57 Figure 26. Overview of the PLEXOS LT Model............................................................................................. 60 Figure 27. Objective Function of Capacity Expansion Problem .................................................................. 61 Figure 28. Simplified Topology for Capacity Expansion Model................................................................... 61 Figure 29. CAISO Market Average Annual Price Forecast, $/MWh ............................................................ 62 Figure 30. Schematic of the Marginal Reliability Planning Process............................................................ 65 Figure 31. Marginal ELCCs by Resource Type from the CPUC 38MMT Scenario........................................ 67 Figure 32. Existing and Planned Resource Marginal ELCC and SVP’s Reliability Need, 2026‐35................68 Figure 33. RPS (Green) and CES (Blue) Compliance Targets....................................................................... 69 Figure 34. CAISO Average Annual Emissions Factor and Carbon Price....................................................... 70 Figure 35. Modeling Parameters that Vary by Scenario or Sensitivity ....................................................... 72 Figure 36. Key Model Outputs.................................................................................................................... 75 Figure 37. SVP Candidate Renewable Resources Mapping to CPUC Aggregation......................................76 Figure 38. Candidate Renewable Resource Options................................................................................... 77 Figure 39. Candidate Solar Monthly Capacity Factor ................................................................................. 78 Figure 40. Candidate Wind Monthly Capacity Factor................................................................................. 79 Figure 41. Candidate Storage Resource Options........................................................................................ 80 Figure 42. Candidate Thermal Resource Options....................................................................................... 80 Figure 43. Candidate Thermal Operating Parameters................................................................................ 80 Figure 44. Emerging Technology Resource Options................................................................................... 82 Figure 45. Emerging Technology Operating Parameters............................................................................ 82 Figure 46. Candidate Thermal Resource Levelized Fixed Costs, 2022 $/kW‐yr.......................................... 84 Figure 47. Levelized Cost of Electricity by Candidate Renewable Technology, 2022 $/MWh....................84 Figure 48 Candidate Storage Resource Levelized Fixed Costs, 2022 $/kW‐yr............................................ 85 Figure 49. Candidate Emerging Technology Levelized Fixed Cost, 2022 $/kW‐yr......................................85 Figure 50. Fuels Included in the SVP IRP Model ......................................................................................... 86 415.391.5100 | 44 Montgomery Street, Suite 1500, San Francisco, CA 94104 | www.ethree.com iii Figure 51. Natural Gas Price Forecast, 2022 $/MMBtu.............................................................................. 87 Figure 52. Hydrogen Price Forecast, 2022 $/MMBtu ................................................................................. 87 Figure 53. TAC Forecast, 2022 $/MWh....................................................................................................... 88 Figure 54. Transmission Deliverability Costs, 2022 $/kW‐yr ...................................................................... 89 Figure 55. Base Scenario Cumulative New Build Capacity.......................................................................... 91 Figure 56. Base Scenario Total Capacity ..................................................................................................... 91 Figure 57. Base Scenario Annual Generation.............................................................................................. 92 Figure 58. Base Scenario Annual Energy Balance of Loads and Resources ................................................ 93 Figure 59. Base Scenario Marginal Reliability Need and Marginal Effective Capacity ...............................94 Figure 60. Base Scenario Marginal Reliability Need and Resource Capacity Accreditation .......................95 Figure 61. Accelerated SB 100 Scenario Cumulative New Build Capacity .................................................. 96 Figure 62. Accelerated SB 100 Scenario Total Capacity.............................................................................. 97 Figure 63. Accelerated SB 100 Scenario Annual Generation...................................................................... 97 Figure 64. Accelerated SB 100 Scenario Annual Energy Balance of Loads and Resources.........................98 Figure 65. Accelerated SB 100 Scenario Marginal Reliability Need and Marginal Effective Capacity ........99 Figure 66. Accelerated SB 100 Scenario Marginal Reliability Need and Resource Capacity Accreditation ..................................................................................................................................................................100 Figure 67. Zero Emissions Scenario Cumulative New Build Capacity ....................................................... 102 Figure 68. Zero Emissions Scenario Total Capacity................................................................................... 102 Figure 69. Zero Emissions Scenario Annual Generation ........................................................................... 103 Figure 70. Zero Emissions Scenario Annual Energy Balance of Loads and Resources..............................104 Figure 71. Zero Emissions Scenario Marginal Reliability Need and Marginal Effective Capacity .............105 Figure 72. Zero Emissions Scenario Marginal Reliability Need and Resource Capacity Accreditation.....106 Figure 73. Scenario Comparison – 2030 Cumulative New Build Capacity ................................................107 Figure 74. Scenario Comparison – 2035 Cumulative New Build Capacity ................................................108 Figure 75. Scenario Comparison – 2035 Total Capacity............................................................................ 109 Figure 76. Scenario Comparison – 2035 Annual Generation.................................................................... 109 Figure 77. Scenario Comparison – 2035 Annual CO2 Emission................................................................. 110 Figure 78. Scenario Comparison – 2035 Annual Cost Relative to Base Scenario (2022 $MM) ................111 415.391.5100 | 44 Montgomery Street, Suite 1500, San Francisco, CA 94104 | www.ethree.com iv Figure 79. Hydrogen Sensitivity Cumulative New Build Capacity ............................................................. 112 Figure 80. Hydrogen Sensitivity Total Capacity......................................................................................... 112 Figure 81. Hydrogen Sensitivity Annual Generation................................................................................. 113 Figure 82. Hydrogen Sensitivity Marginal Reliability Need and Marginal Effective Capacity...................114 Figure 83. Estimated Retail Rates Impacts................................................................................................ 117 Figure 84. Disadvantaged Communities within SVP’s Service Territory................................................... 119 Figure 85. Total Annual Electricity Demand by Scenario (GWh) .............................................................. 129 Figure 86. Annual Energy Efficiency Impact on Electricity Demand by Scenario (GWh)..........................130 Figure 87. Annual Building Electrification Impact on Electricity Demand by Scenario (GWh) .................130 Figure 88. Annual Transportation Electrification Impact on Demand by Scenario (GWh).......................131 Figure 89. Total Annual Electricity Demand by Scenario.......................................................................... 132 Figure 90. Hourly Demand Profile Components....................................................................................... 132 Figure 91. Electrolyzer Costs for Producing Hydrogen and SNG............................................................... 133 Figure 92. Hydrogen Price Forecast.......................................................................................................... 134 415.391.5100 | 44 Montgomery Street, Suite 1500, San Francisco, CA 94104 | www.ethree.com v Acronym Definitions
Acronym Definition
AAEE additional achievable energy efficiency
AAFS annual achievable fuel substitution
AB assembly bill
ATB (NREL) annual technology baseline
BESS battery energy storage system
CAISO California Independent System Operator
CARB California Air Resources Board
CCGT combined cycle gas turbine
CCS carbon capture and storage
CCWD Calaveras County Water District
CDWR California Department of Water Resources
CEC California Energy Commission
CES clean energy standard
COTP California‐Oregon Transmission Project
CPUC California Public Utilities Commission
CRAT capacity resource accounting table
CT combustion turbine
CVP Central Valley Project
CVRP clean vehicle rebate project
DCFC Direct Current Fast Charger
DER distributed energy resource
DMV Department Of Motor Vehicles
DVR Don Von Raesfeld Power Plant
EBT energy balance table
ELCC effective load carrying capability
EV electric vehicle
FERC Federal Energy Regulatory Commission
FO&M fixed operation and maintenance
GEAT GHG emissions accounting table
GHG greenhouse gas
HVAC heating, ventilation, and air conditioning
I&A (CPUC IRP) inputs & assumptions
IEPR Integrated Energy Policy Report
IRA Inflation Reduction Act
IRP integrated resource plan
ITC Investment Tax Credit
LCFS low carbon fuel standard
415.391.5100 | 44 Montgomery Street, Suite 1500, San Francisco, CA 94104 | www.ethree.com vi LCOE levelized cost of energy
LEC Lodi Energy Center
LFC levelized fixed cost
LOLE loss of load expectation
LSE load serving entity
LT (PLEXOS) long‐term model
M‐S‐R PPA M‐S‐R Public Power Agency
NCPA Northern California Power Agency
NREL National Renewable Energy Laboratory
PBC Public Benefits Charge
PCC portfolio content categories
PEV plug‐in electric vehicle
PG&E Pacific Gas and Electric Company
POU publicly‐owned utility
PPA power purchase agreement
PRM planning reserve margin
PTC Production Tax Credit
PUC public utilities code
PV photovoltaic
RA resource adequacy
REC renewable energy credit
RNG renewable natural gas
RPS renewable portfolio standard
RPT RPS procurement table
SB senate bill
SMR small modular reactor
SVP Silicon Valley Power
TAC transmission access charge
TANC Transmission Agency of Northern California
VO&M variable operations & maintenance
WAPA Western Area Power Administration
ZEV zero‐emission vehicle
2023 Integrated Resource Plan      1

1. Executive Summary
The 2023 Integrated Resource Plan (IRP) serves as a long‐term comprehensive roadmap to continue Silicon Valley Power’s long‐standing focus on providing customers with affordable and reliable service while meeting State and local goalsfor greenhouse gas emissionsreduction. The IRP provides a framework showing how Silicon Valley Power continues its transition away from carbon‐emitting resources towards 100% clean energy resources such as wind, geothermal, hydrogen, hydro‐electric, and solar. This aligns with Silicon Valley Power’s greenhouse gas emission reduction targets and is in accordance with the State’s policy goals required by Senate Bill 350 and Senate Bill 100, including the requirement to update itsIRP no lessthan once every five years. The IRP includesthe results of data modeling of customer energy demands balanced against reliability, sustainability, and affordability goals to develop a least‐cost portfolio of resources to meet the needs of Santa Clara ratepayers.

Silicon Valley Power’s 2023 IRP process commenced in 2023 with customer outreach efforts, which indicated that over 75% of the respondents were satisfied with SVP service and that the top concerns are reliability and affordability. On affordability, the respondents would be willing to pay 10‐25% more on their monthly electric bill to achieve clean energy goals faster. These community outreach efforts and directives from the City of Santa Clara set the direction for the current planning process.

In this IRP, Silicon Valley Power presents three scenarios developed using least‐cost optimization, all of which meet or exceed the State’s emission and reliability requirements. The base portfolio meets the California Air Resources Board’s base targets for Silicon Valley Power and Senate Bill 100 target of 60% renewable energy in 2030, using mature renewable technologies (those commercially available today).

The second portfolio moves forward the Senate Bill 100 renewable energy and zero‐carbon generation targets for 2045 to 2035, requires a minimum of 70% carbon‐free energy (60% renewable) in 2030 and 100% carbon free by 2035, and is limited to mature technology options. The third portfolio achieves a zero‐carbon emissions portfolio across all hours of the year and exploresthe use of emerging technologies (such as biogas, hydrogen, and natural gas with carbon capture and storage) to achieve that goal. In each potential portfolio, the powersupply mix will continue Silicon Valley Power’stransition away from carbon‐ based generation, which has already reduced by approximately 50% its carbon emissions per kWh of retail sales since 2017. Figure ES‐1 presents the three scenarios explored in this IRP.

Figure ES‐1. Silicon Valley Power IRP Scenarios
Scenario 1: Scenario 2: Scenario 3:

Base SB 100 Accelerated SB 100 Zero Emissions with
Emerging Technology
Figure ES‐2 shows the cumulative resource additions through 2035 in Scenario 1: Base SB 100 (Base Scenario). In early years there is an addition of wind, solar and storage to meet load growth and reliability requirements. Starting in 2028, geothermal becomes available and is added to the system in addition to wind capacity asit can provide both clean energy and firm capacity. The baseload operating characteristics of geothermal also align with the relatively high 80% load factor of the SVP system. By 2035, the total Executive Summary2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   2
cumulative resource additions include 290 MW geothermal, 590 MW wind, 150 MW solar, and 110 MW storage capacity to meet load growth and clean energy requirements.

Figure ES‐2. Base Scenario Cumulative New Build Capacity Note: Capacity additions begin in 2026
Figure ES‐3 presents the total capacity of the three scenarios in 2035, and although similar there are some key differences in the portfolios.

While the three scenarios have similar resource additions in the near‐term, the scenarios diverge towards the end of the planning horizon as more aggressive clean energy targets are applied in Scenario 2:

Accelerated SB 100 (Accelerated SB 100 Scenario) and Scenario 3: Zero Emissions with Emerging Technology (Zero Emissions Scenario). The Accelerated SB 100 Scenario, which must meet a higher clean energy requirement in 2035 than the Base Scenario results in additional renewable capacity including geothermal wind, and solar, and a larger total installed capacity. The 2035 total capacity of the Zero Emissions Scenario is similar to the Base Scenario, but less than the Accelerated SB 100 Scenario as it includesthe zero‐emission fuel conversion of existing gasresources and other emerging technologies. The emerging technologies, such as building new hydrogen plants and converting existing gas plants to burn on hydrogen or biogas, modeled in thisIRP offer both clean and “firm capacity” attributes and significantly reduces the potential for “overbuilding” of existing mature technologies like solar, wind, and battery storage.

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Figure ES‐3. Scenario Comparison – 2035 Total Capacity
Meeting reliability needs is also a critical component of utility integrated resource planning. All scenarios considered in this IRP achieve and/or exceed SVP’s reliability requirements, following the “marginal reliability need” long‐term planning approach adopted by the California Public Utility Commission for its load serving entities, using marginal ELCC accreditation for all resource types.1 Regarding the annual modeled cost compared to the Base Scenario, which reaches $250 million (2022 $; TAC costs and non‐modeled system costs are excluded) in 2035, the annual modeled cost increases by about $25 million (2022 $) in the Accelerated SB 100 Scenario and increases by $55 million (2022 $) in the Zero Emissions Scenario. (Figure ES‐4). These costs only represent the cost components modeled and do not represent SVP’s total revenue requirement.2 When other forecasted system costs (e.g., TAC and non‐ modeled costs) are included and spread out over retail sales, the estimated 2035 retail rate in the Accelerated SB 100 Scenario and Zero Emissions Scenario is about 1% and 3% higher than the Base Scenario. However, it is important to note that there are large uncertainties in the availability and cost of emerging technologies and zero‐emission fuels by 2035. As discussed above, without the clean firm emerging technologies modeled in this study, achieving zero emissions with only commercially available resources will likely require significant additional resources to maintain reliability, which could result in a higher system cost. Furthermore, the cost of converting some of the existing gas resources to zero‐ emission fuels is potentially optimistic here due to uncertainties in conversion technologies and limited 1 SVP is not a jurisdictional load serving entity subject the California Public Utility Commission. However, as the approach for long‐term resource adequacy requirements and the availability of future input data for SVP (PRM, resource accreditation, etc.) remain uncertain with shifts to new approaches, SVP opted to follow the long‐term planning method for system reliability needs consistent with the Public Utility Commission’s approach for its jurisdictional load serving entities. See Section 6.4 for further details on this approach. 2 Resulting costs are impacted by the inputs and assumptions to the model (such as resource cost forecasts, fuel prices, and load forecasts, among others). The inputs and assumptions were the best available data at the time of the modeling for this IRP.

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data availability at the time of this IRP study. Resource cost and availability uncertainties can have large impacts on the resulting portfolio and system costs, and they should be monitored by SVP in future IRPs.

Figure ES‐4. Scenario Comparison – 2035 Annual Cost Relative to Base Scenario (2022 $MM) Note: Annual modeled cost includes the operational cost of existing/planned capacity, the capital cost, and operational cost of new build capacity. Capital and fixed costs (including PPA cost) of existing/planned capacity, and transmission and distribution costs are not included.

Challenges Ahead to Meet SVP’s IRP Goals
Through studying Scenario 1: Base SB 100 (Base Scenario), which meets the current state policies, and two additional scenarios with more aggressive clean energy requirements in this IRP, multiple challenges are identified as SVP continues to provide affordable, clean, and reliable power to its growing customer load.
 SVP’s load, primarily data center load, is expected to grow substantially throughout the planning horizon. The forecasted annual load in 2035 almost doubles the current system load, and significant resource additions are needed to meet this growing load. Also, unlike other utilities, SVP’s current and forecasted load is dominated by industrial (datacenter) load, which has a high load factor (or average load divided by peak load) of 80%, meaning that the system demand is relatively constant and there is less ability to shape loads to take advantage of certain resource production,such aslow‐costsolar. Therefore, SVP’sfuture portfolio requires both clean resources and firm resources that can ensure there is enough energy to meet system load in all hours.  SVP will need clean firm resources, such as geothermal, to meet future needs in a deep decarbonized system. SVP faces a common challenge of deeply decarbonized systems, which is the ability to provide power reliably without firm dispatchable (emitting) thermal plants. Clean Executive Summary2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   5
firm resources not only provide clean energy, but also firm capacity to help ensure system reliability. The clean, firm, and baseload characteristics of geothermal align well with SVP’s forecasted load growth and load shape and could provide a key clean firm option.  Competition for limited resources in California can add difficulties for SVP to procure some of cost‐effective resources for its system. For example, only a limited amount, about 3,400 MW, of geothermal may be available to California. Furthermore, the CPUC Mid‐Term Reliability order requires CPUC‐jurisdictional LSEs to procure approximately 1,000 MW long lead‐time clean firm resources by 2028, and geothermal is one of the best available candidates to meet that order. An assumption of this IRP is that SVP may not be able to procure that 1,000 MW tranche. SVP would then be limited to a maximum of about 350 MW, which is approximately 15% of the remaining potential. The three scenarios in this IRP build to, or slightly below that limit. However, with the recent IRA including additional incentives for geothermal resources, and with all LSEs in California transitioning to a cleaner portfolio, there is a growing need for clean and firm resources, further driving competition for limited resources, such as geothermal, and adding challenges (and potentially costs) to cost‐effective resource procurement.  SVP faces uncertainties in project delivery timelines. To keep pace with near‐term load growth to 2030 and longer‐term load growth and policy objectives, SVP will need to bring significant quantities of new resources online over the nextseveral years. As development for new resources in California increases to unprecedented rates, SVP may face challenges including, but not limited to supply chain delays, labor shortage, as well as permitting and lengthy interconnection queue processes. To build and begin utilizing new resources, the cost and schedule uncertainty of a complex, multi‐step, multi‐year interconnection process can significantly complicate other parts of the development process, including financing and project costs.  There are uncertainties in long‐term resource cost forecasts. This IRP uses the long‐term resource cost forecastfrom the industry standard public data source, the NREL Annual Technology Baseline (ATB). However, recent market trends have shown that international trade policies and supply chain issues can significantly impact resource costs during procurement. Furthermore, market competition and developer profit markup are difficult to forecast and model but do influence resource costs. While many cost uncertainties are not explicitly studied in this IRP, they can impact the resulting portfolio choices and system costs. SVP should continue to monitor resource costs in future IRPs and resource procurement activities.  Achieving zero emission in every hour will likely require a combination of commercially available resources and new emerging technologiesto be cost‐effective and affordable. To meet the hourly zero‐emission target, all generation needs come from renewable, carbon‐free resources, and/or market purchases (also when market emissions are zero) in every hour. If Executive Summary2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   6
emerging technologies and emerging zero‐emission fuels are not available, SVP would need to add much higher amounts of existing commercially available technologies, such as solar, wind, and battery storage resources. The total nameplate capacity of those resources is likely higher than the system load and the three scenarios presented here. Because they have low and marginally decreasing reliability value, more capacity is needed to cover the most critical hours, even though there might be high curtailment occurring in other normal and/or low load hours.

The emerging technologies, such as building new hydrogen plants and converting existing gas plants to burn on hydrogen or biogas, modeled in this IRP offer both clean and “firm capacity” attributes, and reduces the potential for “overbuilding” existing mature technologies.  There are large uncertainties and risks in emerging technologies. The emerging technologies modeled in this IRP are developed based on various assumptions and limited data. Many of the emerging technologies are still in their research and development and/or piloting phases, and it is difficult to predict when they will be commercially available at scale. Additionally, some emerging technologies, such as green hydrogen, require significant infrastructure development, such as electrolyzers, renewables for electrolyzers, pipelines, and storage. The costs and infrastructure required to support emerging technologies are uncertain and can impact the resulting portfolio feasibility and cost. The development of emerging technologies should continue to be monitored and studied by SVP in future IRPs and resource procurement.  SVP’stransmission capabilities with CAISO can have an impact on how much emission reduction SVP can achieve. DVR and Gianera are the only two resources, both natural gas plants, located within SVP’s local zone. When trying to meet more aggressive clean energy goals and reduce gas generation, the local resources’ roles and SVP’s transmission capabilities with CAISO become important. If the local resources cannot be dispatched to meet SVP’s load, all system load must be met with energy delivered via the transmission line from CAISO. However, the existing and planned transmission capacity may not always be sufficient to cover SVP’s forecasted peak load.

In this IRP, it is assumed that local resources would be able to run on emerging zero‐emission fuel and can be dispatched in Scenario 3: Zero Emissions with Emerging Technology, but SVP should continue to study system transmission capabilities and the clean transition of local resources in future IRPs.
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2.Introduction

2.1. Silicon Valley Power
The City of Santa Clara (Santa Clara) is a charter California city located at the southern end of the San Francisco Bay. Since 1896 Santa Clara, currently under the name Silicon Valley Power (SVP), has provided all electric service within an area coterminous with the city’s boundaries.

SVP is a fully vertically integrated municipal owned (or publicly owned) utility (POU) that provides all aspects of electric services including generation, transmission, and distribution facilities. SVP also purchases power and transmission services from other providers and participates in the California Independent System Operator (CAISO) market. SVP, as a department of Santa Clara, is under the direction of the Chief Electric Utility Officer, who is appointed by and reports to the Santa Clara City Manager. The Santa Clara City Council fulfills the role of a rate making and policy decision board.

SVP has procured renewable energy for multiple decades in the form of wind, hydro‐electric and geothermal generation prior to the establishment of any Renewable Portfolio Standard (RPS) mandates.

SVP continues to make demonstrable progress towards meeting the Senate Bill (SB) 350 long‐term RPS procurement mandates, meeting California’s Resource Adequacy (RA) mandates and providing energy efficiency and electrification rebates within Santa Clara’s boundaries. SVP has installed over 147 public and fleet electric vehicle (EV) charging stations within Santa Clara. In addition, the city has adopted building codes that surpass the requirements of California Title 24 to facilitate more building electrification and EV charging infrastructure at the time of new construction.

Since 2018, SVP reduced its annual greenhouse gas (GHG) emissions by approximately 50%, primarily by divesting from all coal generation and certain natural gas generation.

SVP also maintains affordable electric rates relative to other California load serving entities (LSEs) and a robust discount program for income‐limited residents. Lower rates have been an economic driver for development within Santa Clara, creating a unique customer base with a significant share of large‐ high‐ technology manufacturing and data management facilities. These facilities and other industrial customers accounted for over 90% of SVP’s customer mix, by retail sales, in 2021.

SVP maintains investment grade credit ratings from Fitch and S&P, which has made SVP a desirable counterparty for generation companies.

2.2. State Laws, Policy, and Regulations
This section details the various California laws and regulations passed in recent years that apply to POU’s such as SVP. Although SVP adheres to the guidelines of the California Energy Commission (CEC) as well as the requirements of SB 350 and Public Utilities Code (PUC) 9621, additional laws, policies and regulations also impact long‐term planning conducted by SVP.

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SB 350, the Clean Energy and Pollution Reduction Act, signed in 2015, required POUs with a three‐year (2013‐2016) average annual energy requirement of greater than 700 GWh to file an initial IRP consistent with PUC 9621 with the CEC in 2019, to then be updated at least once every five years. This IRP, SVP’s first update to the 2019 IRP must be approved by the POU (the Santa Clara City Council) by January 1, 2024, and filed with the CEC by April 30, 2024.

PUC 9621 established several targets that impact future resource additions. These include:
 Meet the GHG emissions reduction targets established by the California Air Resources Board (CARB), in coordination with the CEC, for the electricity sector and each public utility that reflect the sector’s share in achieving the economy wide GHG emissions reduction of 40% GHG from 1990 levels by 2030.
 Achieve procurement of a minimum 50% eligible renewable energy resources by 2030 and compliance with the California RPS Program interim goals, which include 40% by 2024 and 45% by 2027.
 These targets are to be met while also complying with PUC 454.52 related to serving customers at just and reasonable rates and minimizing ratepayer impacts, ensuring system reliability, strengthening the transmission and distribution systems, enhancing demand‐side management, and minimizing local air pollutants and other GHG emissions with early priority on disadvantaged communities.

SB 100, the 100 Percent Clean Energy Act, signed in 2018, accelerated the RPS requirements from 50% by 2030 to 60% by 2030 with interim targets of 44% by 2024 and 52% by 2027. SB 100 also requires all of California’s retail electricity supply be met with RPS‐eligible and zero‐carbon resources by December 31, 2045—achieving 100% clean energy.

SB 338, effective in January 2018, requires electric utilities in California to utilize energy efficiency, demand management, energy storage, and other strategies to meet peak demand requirements, ultimately reducing the need for new generation and distribution resourcesin achieving the state’s energy goals at the least cost to ratepayers.

SB 1020, the Clean Energy, Jobs, and Affordability Act, signed in 2022, established additional interim targetsto ensure that California meets SB 100’s 2045 goal of 100% RPS‐eligible and zero‐carbon resources.

These require clean energy generation to reach 90% of retail sales by 2035 and 95% by 2040.

2.3. Relevant State Legislation and Executive Orders
The following sections summarize additional key bills and orders for GHG emissions, energy efficiency, and renewable energy that affect the electric utility industry and have led up to SB 350 and PUC 9621.

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GHG Emissions Reductions
Assembly Bill (AB) 32, or the Global Warming Solutions Act of 2006, extended in 2016, sent an absolute limit on GHG emissions for the state requiring economy wide emissions reductions to 40% below 1990 levels by 2030. AB 32 required utilities to report GHG emissions to the CARB and permitted the CARB to set regulationsfor GHG emissionsreductions—leading to the implementation of a cap‐and‐trade program and GHG Planning Target Ranges for POUs. SVP’s IRP must ultimately align with the requirements of AB

32. SB 1368, or the Emissions Performance Standard, enacted in 2007, restricts new investments in baseload fossil fuel generation resourcesthat exceed the rate of GHG emissionsfor existing combined‐cycle natural gas baseload generation. SB 1368 also allows the CEC to establish a regulatory framework to enforce this standard for POUs. CEC regulations prohibit investment in generation that exceeds 0.55 tons CO2/MWh of electricity produced, with limited exceptions.

Relatedly, SB32, implemented in 2017, requires CARB to ensure the above stated GHG emissions reductions targets are met by 2030, and AB 197, also implemented in 2017, increased the legislative oversight of the CARB. AB 197 also requires that the CARB, in any consideration of limits beyond the existing statewide GHG emissions targets, protect the state’s most impacted disadvantaged communities consider the social costs of emissions, and prioritize emissions reduction rules and regulations that achieve specified results.

AB 1279, signed in 2022, establishes a binding goal for California to achieve caron neutrality no later than 2045 and establishes an 85% emissions reduction of emissions target (below 1990 levels) as part of the goal.

Energy Efficiency
SB 1037, signed in 2005, requires POUs to consider energy efficiency prior to investment in any other resources to meet growing energy demand, pursuant to the statewide commitment to cost‐effective and feasible energy efficiency. One year later in 2006, AB 2021 wassigned into law requiring POUsto establish annual efficiency targets and report on a on a triennial basis over a 10‐year horizon. Subsequent decisions changed the time interval for establishing the annual targets to every four years.

Renewable Energy
The California Renewable Energy Resources Act (SB X1‐2),signed in 2011 codified the RPS target for POUs, but also established specific Portfolio Content Categories (PCCs), which further divided the eligible renewable energy resources to be procured and established limits. The four PCC categories classify renewable resources by interconnection location and additional factors:
 PCC1: Products must be bunded and the POU cannot resell the energy; the resource’s first point of interconnection must be to a distribution system serving end‐users within a California balancing authority area; renewable energy products having a first point of interconnection outside a state Introduction2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   10
balancing authority area must be scheduled hourly into the area without substituting electricity from another source.
 PCC2: Products must be bundled and interconnected to Western Electricity Coordinating Council network; the electricity bust be scheduled into a California balancing authority area; the products must have a first point of interconnection outside of a state balancing authority area, and the electricity must not be in the portfolio of the POU prior to the date of contract or ownership agreement; the electricity must be scheduled into the state balancing authority area within the same calendar year that the electricity is generated, and the energy may not be sold back by the POU.
 PCC3: unbundled renewable energy credits (RECs) and products not meetings the requirements of PCC1 or PCC2
 PCC0: renewable energy under contract prior to June 1, 2010 provided that the resource meets the RPS eligibility requirements in effect when the procurement agreement was executed; subsequent amendments do not increase the capacity or production or substitute a different resource (any such change would be classified into PCC1, 2 or 3 and follow the portfolio balance requirements); and the duration of the contract may be extended if the original contract was for 15 years or more.

2.4. Federal Legislation
Future federal‐level laws or regulations could possibly mandate new renewable and GHG emissions standardsimplemented by the Environmental Protection Agency (EPA) that would impact POU operations.

However, regulation of GHG emissions at the federal level has been uncertain at times, and it is difficult to foresee how future federal policy on GHG emissions may impact on SVP operations. This IRP was prepared assuming that California GHG emission reduction requirements are the most stringent applicable for planning.

2.5. CEC IRP Guidelines
Beginning on January 1, 2019 SVP, as a POU, was obligated by SB 350 to develop and submit it to the CEC to review at least every five years. SVP filed its first IRP with the CEC in accordance with SB 350 in 2019. “Climate change is a real threat to all our lives.

Baby steps aren’t going to be enough.” ‐Santa Clara
resident survey response
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ThisIRP process, will fulfill CEC requirementsfor SVP to receive POU (the Santa Clara City Council) approval of its second IRP by January 1, 2024, and file with the CEC by April 30, 2024.

The CEC developed the Publicly Owned Utility Integrated Resource Plan Submission and Review Guidelines document in July 2017 which established several requirements to be included in the IRP filing process.3 CEC is proposing amendments to the IRP Guidelines; however, as of the writing of this IRP, the proposed changes are not yet formally adopted. Therefore, SVP followed the current approved CEC Guidelines, except for the planning horizon, which is detailed in Figure 1. These requirements include the following:
 POUs must submit the following four standardized tables to the CEC as part of the IRP Filing:
o Capacity Resource Accounting Table (CRAT): Annual peak capacity demand in each year and the contribution of each energy resource (capacity) in the POU’s portfolio to meet that demand.
o Energy Balance Table (EBT): Annual total energy demand and annual estimatesfor energy supply from various resources.
o GHG Emissions Accounting Table (GEAT): Annual GHG emissions associated with each resource in the POU’s portfolio to demonstrate compliance with the GHG emissions reduction targets established by CARB.
o RPS Procurement Table (RPT): A detailed summary of a POU resource plan to meet the RPS requirements.
 The minimum planning period beginsJanuary 1 of the year that the POU’s governing board adopts the IRP and must go through December 31, 2030. POU’s are encouraged to address longer planning periods in post‐2030.
 POUs are encouraged to evaluate alternative resource options through various scenarios and sensitivity analyses.
 The IRP Filing must include supporting information used to develop the Standardized Tables and other studies, data, analyses used or relied upon in developing the IRP.  POUs are required to report the forecasted peak demand in the CRAT and forecasted retail sales, other loads, and net energy for load in the EBT. The IRP must explain the demand forecasting methodology and assumptions used. The CEC encourages alternative demand forecast scenarios to be part of the IRP.
3 CEC, “Publicly Owned Utility Integrated Resource Plan Submission and Review Guidelines ‐ Adopted” (Sacramento, CA:

California Energy Commission (CEC), 2017), https://www.energy.ca.gov/rules‐and‐regulations/energy‐suppliers‐ reporting/clean‐energy‐and‐pollution‐reduction‐act‐sb‐350‐0.

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 The IRP must report the mix of resources in the required tables; this includes RPS procurement information in the RPT. The mix of resources refers to short‐term and long‐term electricity, electricity‐related, and demand response products. RPS information provided must demonstrate the achievement of the RPS target by listing the RPS procurement targets, the projection of renewables as contained in a RPS procurement plan. The reporting of resource mix must also include the impacts of energy efficiency and demand response resources. Energy storage and transportation electrification should also be addressed in the IRP and included in the required tables, as appropriate.
 The IRP should address system reliability. This includes explaining how the planning reserve margin (PRM) was established and a discussion of any local transmission constrained areas.  GHG emission intensities must be reported in metric tons of carbon dioxide equivalent (CO2e) per MWh for each supply resource reported in the EBT.
 The IRP should be consistent with the goal of achieving just and reasonable rates and must include as supporting information, a report on rate impacts under the IRP plan if that report was considered in the IRP planning.
 The IRP should report on the contribution of the IRP to increasing the diversity, sustainability, and resilience of the transmission and distribution system.  The IRP should be consistent with minimizing localized air pollutants and other GHG emissions with early priority on disadvantaged communities.

Figure 1 summarizes the IRP filing requirements as listed in the CEC guidelines document. The location where this information can be found in SVP’s IRP is outlined below.

Figure 1. Summary of CEC IRP Filing Requirements
Item CEC Guidelines IRP Location
A. Planning Horizon
and Objective of
Expansion Plan
“requires each POU to adopt an IRP that ensures the utility achieves specific goals and targets by 2030, including meeting the electricity sector and utility specific GHG emissions reduction targets established by the CARB that reflect the electricity sector’s percentage in achieving economy‐wide GHG emissions reductions of 40% below 1990 levels, and ensuring procurement of at least 50%of eligible renewable resources…The minimum planning horizon that achieves this objective begins no later than January 1 of the year that the POU’s governing board adopts the plan and ends no earlier than December 31, 2030”.*
*Proposed revisions through 20454
Section 2
4 CEC, “Publicly Owned Utility Integrated Resource Plan Submission and Review Guidelines ‐ Draft Proposed” (Sacramento, CA:

California Energy Commission (CEC), 2022), https://www.energy.ca.gov/publications/2022/publicly‐owned‐utility‐integrated‐ resource‐plan‐submission‐and‐review‐guidelines.

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B. Scenarios and
Sensitivity Analysis
“POUs are encouraged to also evaluate other scenarios and sensitivity analyses to consider the feasibility and cost‐effectiveness (and rate impacts) of alternative resource options.”
Sections 6 and
8 C. Standardized Tables
“POUs must submit the following four standardized tables to the Energy Commission as part of the IRP Filing.”
Capacity Resource Accounting Table (CRAT)
Energy Balance Table (EBT)
RPS Procurement Table (RPT)
GHG Emissions Accounting Table (GEAT)
Appendix D
D. Supporting
Information
“(1) analyses, studies, data, and work papers, or other material that the POU used or relied upon (including inputs and assumptions) in creating the IRP…(2) additional information required by these guidelines. Supporting Information supplements the data submitted in the standardized tables and must be submitted to the Energy Commission as part of the IRP Filing”
Sections 3, 4, 5,
6, 7 and
Appendix A
Appendix C
E. Demand Forecast

1. Reporting Requirements:
“report annual forecasted peak demand (megawatt [MW]) in the CRAT and annual forecasted retail sales, other loads, and net energy for load in the EBT”

2. Demand Forecast Methodology and Assumptions:
“describe the demand forecasting methodology and assumptions used.”

3. Demand Forecast – Other Regions
“If the POU uses system modeling as part of the IRP development, the IRP Filing must include the demand forecast assumptions for regions outside the POU jurisdiction.”
Section 3,
Appendix B
F. Resource
Procurement Plan
“The IRP Filing must report the mix of resources used by the POU in the IRP. This information must be reported on the CRAT, EBT, and GEAT, and RPS procurement must be reported on the RPT.” The IRP Filing must address the following:

Diversified Procurement Portfolio
RPS Planning Requirements
Energy Efficiency and Demand Response Resources
Energy Storage
Transportation Electrification
Section 8,
Appendix D
G. System and Local
Reliability
“requires Filing POUs to adopt an IRP to ensure that each POU meets the goal of ensuring system and local reliability.”

1. Reliability Criteria
“must include projections of annual peak capacity needs and the contribution of both demand and supply‐side resources… must report the PRM and how it was determined.”

2. Local Reliability Area
“must identify any local transmission constrained areas in the POU service territory”

3. Addressing Net Demand in Peak Hours
“must include a narrative describing how existing renewable resources, grid operational efficiencies, multi‐hour energy storage, and distributed energy resources (DERs), including energy efficiency, were considered for meeting energy and reliability needs during the net‐peak hours.”
Sections 6, 7, 8,
and Appendix D
H. Greenhouse Gas
Emissions
“requires POUs to adopt an IRP to ensure the utility meets, by 2030, the GHG emissions reduction target established by CARB…must Sections 6, 8,
Appendix D
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report in the GEAT estimated emissions intensities (in metric tons of CO2e per/megawatt hour [mt CO2e/MWh] and total metric tons of carbon dioxide [mt CO2e] emissions for each supply resource reported in the EBT.”
I. Retail Rates
“requires POUs to adopt an IRP to ensure the POU achieves the goals of fulfilling its obligation to serve its customers at just and reasonable rates and minimizing impacts on ratepayer bills… must include, as Supporting Information, a report or study on rate impacts under the IRP scenario”
Section 8
J. Transmission &
Distribution Systems
“ensure that the POU achieves the goal of strengthening the diversity, sustainability, and resilience of the bulk transmission and distribution systems, and local communities.”
Section 4 and 7
K. Localized Air
Pollutants and
Disadvantaged
Communities
“ensure the POU achieves the goal of minimizing localized air pollutants and other GHG emissions, with early priority on disadvantaged communities”
Section 8

2.6. Public Stakeholder Engagement
The public stakeholder engagement process for the IRP involved seeking groups who have an interest in future energy resource plans (i.e., stakeholders), gathering their feedback and addressing their goals and concerns. Through this process, participants were engaged and involved early in IRP development.

Stakeholders included large customers, local businesses, and the community at large.

The community engagement activities that shaped the IRP were conducted in two phases. The first phase was the creation of the Santa Clara Climate Action Plan, organized by Santa Clara and a consultant team in 2020 and 2021. The community feedback collected during this process was used to help shape the Climate Action Plan, which would then be used as a guiding document for the IRP. The Climate Action Plan community engagement included:
 Online surveys,
 Virtual community workshops,
 Focus group interviews, and
 Public comment on the draft CAP.

Additional community engagement specifically for the IRP included:
 A community survey, open from September – November 2023 (results are in Appendix A)  A community workshop was presented in‐person and virtually, attended by both residential and commercial customers.
 Publication through newsletters.
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 Informational outreach and survey promotion at the Santa Clara Art & Wine Festival and the State of the City Events
There are plans to hold another community workshop after the IRP is presented to the City Council in December 2023 to discuss the results and the path forward.

2.7. The Integrated Resource Planning Process
Integrated Resource Planning identifies a long‐term resource portfolio plan that provides for future peak load and energy demand, while maintaining system reliability, and achieves a reasonable balance between fiscal responsibility and environmental stewardship. The IRP is a formal planning document to be submitted for approval by the Santa Clara City Council prior filing with the CEC.

The IRP process can be summarized in the following steps:

1. Identify Objectives: Establish a clear vision with a set of goals for the IRP that will drive the planning process and ground it in the priorities and concerns of local stakeholders (Figure 2).

2. Design Scenarios: Build realistic potential futuresthat capture the key external forces and internal planning decisions to be explored in the IRP.

3. Determine Future Capacity Needs: Utilizing the latest load forecast that incorporates load modifiers for energy efficiency and transportation and building electrification and comparing that to current information for existing supply‐side resources, expected retirement dates, and planned resource additions, identify a baseline for future capacity needs.

4. Identify Resource Options: Identify potential candidate resources that can be reliably utilized to serve load if a need is determined. This requires consideration of technology advancements, cost, resource location and potential, and performance characteristics.

5. Analyze Resource Options: Conduct analyses to identify resource options that ensure reliability and regulatory compliance at least cost.

6. Evaluate Resource Portfolios: Compare least‐cost resource portfolios, their costs, achievement of policy goals (i.e., GHG, clean energy, and reliability), and potential rate impacts to understand trade‐offs, and achievement of planning objectives.
“Consider cost and reliability above other
considerations.” ‐Santa Clara resident
survey response
“I have no trouble paying extra for electricity to
accelerate sustainability.” ‐Santa Clara resident
survey
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7. Finalize Plan: SVP will work with the Santa Clara City Council to a identify preferred, cost‐effective portfolio resource expansion plan to file with the CEC, and update, as appropriate, as part of ongoing utility due diligence. The current document presents a set of scenarios to aid decision making; however, a preferred scenario is not identified.

The goal of SVP’s 2024 IRP is to “identify a plan that meets or exceed the State’s clean energy mandates while balancing affordability and reliability,” with the core objectives shown in Figure 2 that support SVP’s vision for the 2024 to 2035 planning horizon.

Figure 2. Core Objectives of SVP’s IRP
The sections that follow detail the additional steps of the SVP’s planning process.

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3. Energy and Demand Forecast

3.1. Historic Energy Use and Demand
As of 2022, Santa Clara’s population was estimated at just over 128,000, and SVP served approximately 60,000 customer meters with 4,400 GWh of sales and a peak demand of 693 MW. The makeup of SVP’s customer base is unique for the state. While 85% of the total number of customers are residential, over 93% of the utility retail sales are to commercial and industrial customers, consisting of high‐technology manufacturing and data management facilities, shown in Figure 3. This results in a relatively flat demand profile and a high load factor. SVP’s demand has consistently increased in recent years, mostly due to growth of the industrial customer sector.

Figure 3. SVP Customer Mix by Retail Sales in 2022

3.2. Demand Forecast Methodology and Assumptions
A range of sources were leveraged to develop an SVP Reference scenario for the planning horizon 2024‐ 2035 of annual peak load and an hourly energy demand forecast.5 The Reference Scenario is a business‐ as‐usual forecast of energy demand in SVP territory using the utility’s baseline forecast of energy demand with additional energy efficiency and electrification projections from the Planning Forecast of the CEC 2022 Integrated Energy Policy Report (IEPR).6
5 Sensitivities were also explored to build High electrification and a IEPR local reliability load forecast, discussed in Appendix B. 6 CEC, “CEC 2022 Integrated Energy Policy Report (IEPR)” (Sacramento, CA: California Energy Commission (CEC), 2022), https://www.energy.ca.gov/data‐reports/reports/integrated‐energy‐policy‐report/2022‐integrated‐energy‐policy‐report‐ update.

Commercial

2.1%
Industrial

91.6%
Municipal

0.4%
Residential

5.9%
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Annual Energy Demand Forecast
Baseline Energy Demand
SVP baseline energy demand is developed from hourly energy forecasts for 2023‐2035 originally submitted as part of the 2022 IEPR process and the Pacific Gas and Electric (PG&E) extended IRP process.7 SVP also utilized annual energy forecastsfor 2023‐2035 by customer classfor the Residential, Commercial, Industrial, and Municipal customer sectors. As shown in Figure 4, baseline energy demand grows quickly from 2023 to 2035 mainly due to increases in the Industrial sector (e.g., datacenter loads).

Figure 4. SVP Baseline Energy Demand Forecast (GWh)
Customer Class 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Residential 271 290 321 366 430 469 481 485 485 487 485 502 502 Commercial 98 132 161 195 241 288 325 355 355 356 355 368 368 Industrial 4,184 4,555 5,078 5,521 5,882 6,396 6,810 7,249 7,729 8,234 8,498 8,642 8,810 Municipal 17 17 17 17 17 17 17 17 17 17 17 18 18
Baseline Total 4,570 4,993 5,577 6,099 6,570 7,170 7,633 8,106 8,586 9,094 9,356 9,530 9,698 Energy Demand Modifiers
After establishing the baseline energy demand forecast, load modifiers for energy efficiency, building electrification, and transportation electrification were developed and layered onto the baseline forecast to establish the total annual demand for the Reference Scenario. Figure 5 shows these energy demand modifiers and SVP resulting total annual demand, and the assumptions behind these modifiers are explained in the following paragraphs. The Reference Scenario also includes a 2.9% line‐loss factor for losses between the CAISO point of interconnection and SVP's retail load when reporting final electricity demand.8

Figure 5. Reference Scenario Annual Electricity Demand and Demand Modifier Impacts (GWh) Scenario 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Baseline Total 4,570 4,993 5,577 6,099 6,570 7,170 7,633 8,106 8,586 9,094 9,356 9,530 9,698 Energy
Efficiency ‐62 ‐97 ‐136 ‐171 ‐204 ‐226 ‐248 ‐271 ‐294 ‐313 ‐333 ‐350 ‐365 Building
Electrification 13 21 29 36 43 51 59 67 74 81 88 94 99
Transportation
Electrification 8 15 24 32 40 49 59 69 81 94 107 120 135 Total Annual 4,529 4,933 5,494 5,995 6,449 7,044 7,503 7,971 8,448 8,955 9,218 9,394 9,567 For energy efficiency the Reference Scenario reflects the “Scenario 3 (Mid)” additional achievable energy efficiency (AAEE) modeled by CEC from the 2022 IEPR for Residential and Commercial sector energy efficiency, aligning with the assumptions used in the 2022 IEPR Planning Forecast.9 These assumptions lead to 130 GWh and 169 GWh of annual savings by 2035 for the residential and commercial sectors, 7 SVP, “SVP Hourly Energy Forecasts: 2023‐2035,” 2023, Data Provided by Silicon Valley Power. 8 Line‐loss factor from SVP 9 CEC, “2022 IEPR AAEE‐AAFS Annual Impacts,” 2022, https://efiling.energy.ca.gov/Lists/DocketLog.aspx?docketnumber=22‐ IEPR‐03.

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respectively, from measures targeting lighting, heating, ventilation, and air conditioning (HVAC), water heating, and other end uses. Finally, the Reference scenario includes the cumulative total energy efficiency potential of 66 GWh by 2031, with most of these savings occurring for non‐residential customers.

For building electrification assumptions, the Reference Scenario follows the assumptions of “Scenario 3 (Mid)” Annual Achievable Fuel Substitution (AAFS) modeled by CEC for the 2022 IEPR, aligning with the assumptions used in the 2022 IEPR Planning Forecast.

Finally, the Reference Scenario reflects the base level of transportation electrification from the 2022 IEPR assumptions from CEC. The total annual electricity demand for the Reference Scenario is shown in Figure

6. Figure 6: Total Annual Electricity Demand ‐ Reference Scenario Hourly Energy Demand Forecast
To facilitate capacity expansion modeling for the integrated planning process an hourly demand forecast was developed from this annual forecast. A separate hourly load profile was assigned to the annual baseline energy demand, energy efficiency and electrification load modifiers to develop a complete hourly energy demand forecast for the Reference Scenario forecast. Figure 7 lists the sources used to develop these hourly demand profiles.

As IEPR does not provide an hourly load profile for SVP, PG&E‐wide hourly load shapes for energy efficiency and building and transportation electrification were downscaled from the 2022 IEPR PG&E Planning Scenario.

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Figure 7. Hourly Demand Profile Components
Energy Demand Component Source for Hourly Demand Profile Baseline Energy Demand SVP Hourly Energy Demand Forecast 2023‐2035 Energy Efficiency 2022 IEPR Hourly Forecast – PG&E Planning Scenario10 Building Electrification from 2022 IEPR
Transportation Electrification
10 CEC, “CED 2022 Hourly Forecast ‐ PGE ‐ Planning Scenario,” 2022, https://efiling.energy.ca.gov/Lists/DocketLog.aspx?docketnumber=22‐IEPR‐03.

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4. Existing and Planned System and Resources

4.1. Existing Resources and System Description
This section provides a description of all the resources currently procured to meet customer load. SVP’s portfolio includes Santa Clara‐owned resources, jointly owned resources, and resources procured through Power Purchase Agreements (PPAs). Santa Clara is a member of two joint powers agencies: the Northern California Power Agency (NCPA) and the M‐S‐R Public Power Agency (M‐S‐R PPA).11 Each of these agencies has shared interests in several facilities, as described later in this section.

This IRP accounts for Santa Clara’s Metered Subsystem Aggregation Agreement (MSSA) between the NCPA and California Independent System Operator (CAISO). The NCPA serves as SVP’s schedule coordinator and is not obligated to offer its generation into the CAISO market. SVP pays a Transmission Access Charge (TAC) to CAISO for energy delivered into its service area (see Sections 4.7 and 7.5).

SVP’s energy resource planning strategies, methods and processes are consistent with applicable Western Electricity Coordinating Council and North American Electric Reliability Corporation (NERC) standards, SVP’s Strategic Plan, the MSSA and other relevant contracts into which Santa Clara has entered, good utility practice, and sound economic and business principles. SVP will continue to maintain an integrated and balanced portfolio of resources that is sufficient to meet its obligations.

When procuring resources to serve customer load, risk management processes and procedures are followed using Santa Clara’s official Risk Management Policy. Risk management practices apply to decisions concerning the mix of resources and their loading order, including the decision to use supply or demand‐side resources, whether to operate inside Santa Clara versus remote resources, what type of generation to procure and other questions. In general, SVP’s approach is to maintain a diverse portfolio of generating resources and market energy resources to reduce risk and minimize exposure to loss of generating capacity. Due to SVP’s dependence on transmission services provided by the CAISO and others to import power, SVP is exposed to costs increases and to potential power delivery interruptions failures.

SVP continually seeks strategies to reduce the impacts of transmission cost increases and maintains contingency plansforsuch occurrences. SVP also procuresfuel for its natural gas‐fired generating facilities with supply contracts that are laddered with staggered start times and durations to limit its exposure to fuel price fluctuations.

A summary of SVP’s calendar year 2022 generation portfolio mix by resource type is presented in Figure

8. This does not include SVP’s excess renewable resources sold to third parties. Due to SVP’s long position in renewables, SVP will either sell excess renewable generation to other entities, or bank surplus RECs for 11 M‐S‐R Public Power Agency (M‐S‐R PPA) was created through a Joint Exercise of Powers Agreement among Modesto Irrigation District, the City of Santa Clara (as Silicon Valley Power), and the City of Redding for the purposes of acquiring, constructing, operating, and maintaining, any project for the purpose of providing electrical energy or other project benefits for public or private uses.

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utilization in future years. This allows SVP to evaluate additional eligible renewable resources projects that will optimize the value for the customers.

Figure 8. SVP Generation Portfolio Mix by Technology, 2022

Note: Unspecified Power is electricity that has been purchased through open market transactions and is not traceable to a specific generation source.

4.2. Existing and Planned Resources
SVP’s portfolio of existing (owned, jointly owned and/or contracted) generators and planned resource additions through the modeling horizon to 2035 is shown in Figure 9. This portfolio includes resources that are currently in SVP’s portfolio, those that are planned for future delivery, and those that retire within the planning horizon.

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Figure 9. SVP Existing and Planned Resource Portfolio, 2024‐2035 More information on the individual resources under contract to deliver electricity in 2023 to SVP is provided in Figure 10.

Figure 10. SVP’s Resource Portfolio in 2023
Portfolio Resource Type RPS
Eligible
PCC
Type
System
RA Capacity, MW
City-Owned /
Contracted
Tri-Dam Donnells Hydro No Yes 72.0
WAPA Base Resource Hydro No Yes 126.0
Ameresco Forward Landfill Gas Yes PCC1 Yes 4.2
Ameresco VASCO Landfill Gas Yes PCC1 Yes 4.3
G2 Landfill Landfill Gas Yes PCC0 Yes 1.6
Donald Von Raesfeld (DVR) Natural Gas No Yes 147.8
Gianera Generating Station Natural Gas No Yes 49.5
Black Butte Small Hydro Yes PCC0 Yes 6.2
Camp Far West Hydro (Index+) Small Hydro Yes PCC1 Yes 6.8 Friant 1 Small Hydro Yes PCC1 Yes 25.0
Friant 2 (Quinten) Small Hydro Yes PCC1 No 7.3
Grizzly Hydro Small Hydro Yes PCC0 Yes 17.7
Rio Bravo (Index+) Small Hydro Yes PCC1 Yes 14.0
Stony Gorge Small Hydro Yes PCC0 Yes 4.9
Tri Dam Southern/Sandbar Small Hydro Yes PCC1 Yes 16.2
Tri-Dam Beardsley Small Hydro Yes PCC1 Yes 11.5
Tri-Dam Tulloch Small Hydro Yes PCC1 Yes 25.9
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Aquamarine Westside (Index+) Solar Yes PCC1 Yes 75.0
Central 40 Solar Yes PCC1 Yes 40.0
Rosamond Solar Solar Yes PCC1 Yes 20.0
Manzana Wind Wind Yes PCC1 Yes 50.0
Total, City-Owned and Contracted 725.9
NCPA
Geo Plant 1-4 4 Geothermal Yes PCC0 Yes 58.4
Collierville Hydro No Yes 91.4
South Feather - Woodleaf Hydro No Yes 38.5
South Feather – Forbstown Hydro No Yes 24.0
Alameda 1 & 2 Natural Gas No Yes 19.6
Lodi CT Natural Gas No Yes 9.9
Lodi Energy Center (LEC) Natural Gas No Yes 77.9
New Spicer Small Hydro Yes PCC0 Yes 2.2
South Feather – Kelly Ridge Small Hydro Yes PCC1 Yes 7.0 South Feather – Sly Creek Small Hydro Yes PCC1 Yes 8.3
Total, NCPA-Owned and Contracted 337.2
MSR Big Horn 1 Wind Yes PCC0 Yes 105.0
Big Horn 2 Wind Yes PCC0 Yes 17.5
Total, MSR Resources 122.5

Total, Renewable 529.0
Total, Zero Carbon Resources 880.9
TOTAL 1,185.6
SVP’s diverse portfolio of resources is located throughout California and Washington State and soon in the Country of Mexico, as mapped in Figure 11.

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Figure 11. SVP’s Current Power Resource Locations (Owned and Contracted) Additional resources that are under contract and scheduled to come online in future years are summarized in Figure 12.

Figure 12. SVP’s Planned Resource Additions in Future Years Portfolio Resource Type RPS
Eligible
System
RA
Delivery
Year
Capacity,
MW
City-Owned /
Contracted
BESS 200 MWh Li-ion Battery No Yes 2025 50.0
Calpine Geothermal 1 Geothermal Yes Yes 2025 35.0
Calpine Geothermal 2 Geothermal Yes Yes 2027 35.0
Rooney Ranch Wind Yes Yes 2026 19.0
Sand Hill A Wind Yes Yes 2026 13.0
Sand Hill B Wind Yes Yes 2026 17.5
Cimmaron Wind Wind Yes No 2026 300.0
Total, City-Owned and Contracted 469.5
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Several resources in SVP’s portfolio are expected to be retired due to aging units or expiration of the PPA contracts. The schedule of planned contract expirations and resource retirementsis provided in Figure 13.

Among the resources leaving SVP’s portfolio are 8.5 MW of biogas generators and 172.5 MW of aging wind assets.

Figure 13. Planned Resource Retirements
Year Capacity Retired
(MW)
2026 105.0
2032 50.0
2034 8.5
2035 17.5

4.3. Description of Santa Clara Owned and Contracted Resources Aquamarine Westside Solar
In 2021, Santa Clara entered into a PPA with Aquamarine Westside LLC., a solar PV generator project located in Kings County, CA. Under this agreement SVP owns a share of the system and receives up to 75 MW of the total project.

Ameresco Landfill Gas
In 2010, Santa Clara signed PPAs with Ameresco for the Ameresco Forward and Ameresco Vasco projects.

Ameresco Forward is a landfill gas generator located in Manteca, CA. Ameresco Vasco is a landfill gas generator located near Livermore, CA. SVP is contracted to receive up to 4.6 MW (and potentially up to

9.2 MW) from Ameresco Forward and up to 5 MW from Ameresco Vasco.

Stony Creek Hydroelectric System
SVP owns and operates the Stony Creek Hydroelectric System, which consists of three small hydroelectric plants. The 4.9‐MW Stony Gorge generator is located at the Stony Gorge Dam near Willows, CA. The 6.2‐ MW Black Butte generator is located at the Black Butte Dam near Orland, CA. A third, 0.53‐MW generator located near the Black Butte dam, is not modeled.

Central 40 Solar
In 2017, Santa Clara signed a PPA with Samsung to develop the Central 40 project. Central 40 is a solar PV generator located in Stanislaus County, CA. SVP is contracted to receive 40 MW from the project.

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Donald Von Raesfeld (DVR)
In 2005, Santa Clara commissioned the Donald R. Von Raesfeld (DVR) natural gas combined cycle power plant located within the City of Santa Clara. DVR is a 122 MW nominal / 147 MW peaking generator. SVP economically bids DVR into the CAISO market and is operated based on CAISO dispatch instructions.

Friant 1 & 2 Hydro Facilities
In 2016, Santa Clara signed a PPA with the Friant Power Authority for Facility 1. Facility 1 consists of three run‐of‐river hydroelectric facilities in Madera County, CA, totaling 25 MW: the River Outlet (2 MW), the Friant‐Kern (15 MW), and the Madera (8 MW). SVP is contracted to purchase up to 68,000 MWh per year from Facility 1.

In 2012, Santa Clara entered a PPA with the Friant Power Authority for Facility 2, a run‐of‐river hydroelectric generatorin Madera County, CA. Facility 2 consists of the Quinten Luallen Power Plant, rated at 7.3 MW.

G2 Landfill Gas
In 2009, Santa Clara signed a PPA for the G2 landfill gas project in Wheatland, CA. G2 has a nameplate rating of 1.6 MW.

Gianera Generating Station
In 1987, Santa Clara completed the construction of the Gianera Generating Station, located within the City of Santa Clara. Gianera consists of two dual‐fuel (natural gas and fuel oil) combustion turbines, each with a nominal rating of 25 MW. Gianera 1 & 2 combine to provide 49.5 MW of capacity for SVP. Due to the plant’s air permit, Gianera can only be operated up to 877 hours annually.

Grizzly Hydro Project
In a 1990 settlement agreement with PG&E, Santa Clara purchased the Grizzly Creek hydroelectric facility in Plumas County, CA. Grizzly Creek is nominally a 20‐MW facility, and SVP contracted to receive all electricity produced by the system, less transmission losses, which amounts to an effective contracted capacity of 17.7 MW.

Manzana Wind
In 2012, Santa Clara signed a PPA with Avangrid for the Manzana Wind Power Project. Manzana is a 50‐ MW wind project located in Kern County, CA.

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Rosamond Solar
In 2011, SVP entered PPA with Recurrent Energy for the entire output from the RE Rosamond One LLC project, a 20‐MW solar PV project in Kern County, CA.

Rio Bravo
In 2019, Santa Clara signed a PPA with the Olcese Water District for the Rio Bravo project. Rio Bravo is a 14‐MW hydroelectric power plant located in Kern County, CA.

Jenny Strand Solar Park
Santa Clara originally entered into an agreement with MiaSole on December 6, 2011, for the purpose of having MiaSole donate one thousand (1,000) solar PV modules to Santa Clara at no cost to Santa Clara to further the city’s ability to provide renewable power.12 Tioga Solar
On February 2, 2012, Santa Clara entered a 20‐year PPA with Tioga Solar Santa Clara, LLC. The project is located on the City of Santa Clara’s multi‐level parking structure on Tasman Drive in the City of Santa Clara.

Nameplate capacity is 389.76 kW. 13
Tri‐Dam Large and Small Hydroelectric Project
In 2013, Santa Clara signed a PPA with the Tri‐Dam Power Authority to purchase the output from four hydroelectric power plants located on the Middle Fork of the Stanislaus River in Tuolumne County. The Donnell’s Powerhouse is a large hydroelectric generator rated at 72 MW. The other three power plants are small hydroelectric generators: Tulloch (25.9 MW), Beardsley (11.5 MW), and Southern (16.2 MW).

Western Area Power Administration
In 2005, Santa Clara signed a PPA with the Western Area Power Administration (WAPA) for the purchase of hydroelectricity from the Central Valley Project (CVP). In 2021, Santa Clara City Council approved an amendment to the PPA extending the purchase of output through calendar year 2054. The CVP is a collection of federal hydroelectric facilities operating in Northern California. SVP is contracted to receive approximately 9.6% of the electricity from WAPA, which translates to a nameplate capacity of approximately 126 MW.
12 Because of the size of this resource relative to the City’s load, it was not included in the model for this IRP. 13 Like the Jenny Strand Solar Park, due to the size of this resource relative to the City’s load, it was not included in the model.

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Altamont Wind Repower
In 2016, Santa Clara commenced a re‐power project with S‐Power at its existing Altamont Wind Project site. S‐Power will own and operate 19 MW capacity of wind generation. Two additional PPAs were entered with S‐Power under the Rooney Ranch, LLC, including Sand Hill A (13 MW) and Sand Hill B (17.5 MW). In total, the re‐power project will be upgraded to deliver 49.5 MW of capacity to SVP and is scheduled to be completed by 2026.

Kifer Receiving Station Battery Energy Storage System Project SVP is currently contracting with a third party to build and operate a 50‐MW, 4‐hour (200 MWh) utility‐ scale lithium‐ion BESS within the City of Santa Clara at the City’s Kifer Receiving Station. The BESS project is expected to be completed in late 2025.

Cimmaron Wind
SVP entered a PPA for the long‐term supply of renewable energy from Cimmaron, a cross‐border wind generation facility under development in Baja California, Mexico. Cimarron is expected to be a 300 MW wind generation facility that utilizes existing cross‐border high voltage transmission line to interconnect and deliver clean energy to the East County Substation in San Diego County. The project has a commercial operation date of December 31, 2025.

4.4. Northern California Power Agency (NCPA) Resources
Santa Clara, together with the Cities of Alameda, Biggs, Gridley, Healdsburg, Lodi, Lompoc, Palo Alto, Redding, Roseville and Ukiah, the Plumas‐Sierra Rural Electric Cooperative, the Truckee‐Donner Public Utility District, the Bay Area Rapid Transit District and the Port of Oakland, is a member of the California joint powers agency known as Northern California Power Agency (NCPA). The resources that Santa Clara jointly shares with other NCPA members are presented here.

NCPA Hydroelectric Project
In 1982, the NCPA jointly developed the NCPA Hydroelectric Project with the Calaveras County Water District (CCWD). CCWD is the licensee and NCPA is the project operator. The NCPA Hydroelectric Project includes the 246.86 MW Collierville Powerhouse and 6.0 MW Spicer Powerhouse. Santa Clara has a 37% share in NCPA’s Hydroelectric Project, amounting to 91.4 MW of the Collierville project and 2.2 MW of Spicer.

NCPA Geothermal Project
The NCPA owns and operates geothermal projects in Sonoma and Lake Counties, CA. NCPA’s leasehold agreement with the federal government was renewed in 2013. The Geothermal Project consists of two electric generating stations (Geothermal Plant 1 and Geothermal Plant 2), each with two 55‐MW Existing and Planned System and Resources2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   30
nameplate turbines. Santa Clara is contracted for 54.65% and 34.13% entitlement shares, respectively, in both plants.

NCPA Combustion Turbine Project No. 1 – Alameda 1 & 2 and Lodi CT NCPA owns and operates the Combustion Turbine Project Number One (CT 1) (the Combustion Turbine Project), originally consisting of five CT units, each nominally rated 25 MW. Two of the units are in the City of Roseville, two are in the City of Alameda and one is in the City of Lodi. Santa Clara purchased a 25% entitlement share in NCPA’s Combustion Turbine Project pursuant to a power sales contract with NCPA, which has recently been amended to reflect that Santa Clara’s 25% share comes specifically from the two Alameda plants (Alameda CT 1 & 2) and the one Lodi plant (Lodi CT).

NCPA Lodi Energy Center Project
NCPA owns and operatesthe Lodi Energy Center (LEC), a 302 MW natural gas‐fired, combined‐cycle power generation plant located in Lodi, CA, which was placed into commercial operation in 2012. Pursuant to the LEC Power Sales Agreement, Santa Clara has purchased from NCPA a 25.75% generation entitlement share of the capacity and energy from LEC.

NCPA Lodi Energy Center Project – Hydrogen Transition
NCPA is planning a transition of natural gas units to hydrogen beginning with LEC’s conversion to a 45% hydrogen blend in 2027. By 2032, NCPA expects to have LEC running on 100% hydrogen.

For the 45% hydrogen blend in 2027, NCPA plans to install an electrolyzer with 60 MW of capacity at the LEC providing the capability of producing 24 tons of hydrogen per day. The cost of the electrolyzer is expected to be $145 million with an additional $80 million needed for the installation. By 2032, NCPA estimates an additional 360 MW of electrolyzer capacity will be needed to operate LEC at 100% hydrogen, at a rough cost of an additional $2 billion. The renewable generation that powers the electrolysis (for hydrogen generation) would be eligible for the standard IRA tax incentives.

South Feather River Hydroelectric
In 2021, Santa Clara entered a PPA, via third party agreement with NCPA, to purchase 64.2% of the electricity output from the South Feather Power Project. The project consists of four hydroelectric power plants: the 37.5 MW Forbestown Powerhouse, the 11 MW Kelly Ridge Powerhouse, the 13 MW Sly Creek Powerhouse and the 60 MW Woodleaf Powerhouse. The four plants that make up the South Feather Power Project are located across Butte, Plumas and Yuba counties on the South Fork of the Feather River and Slate Creek. Santa Clara’s project participation share of the generation output is expected to be approximately 245 GWh annually.

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Camp Far West Hydroelectric
In 2022 Santa Clara entered into a PPA, via third phase agreement with the NCPA, with the South Sutter Water District for the generation output of the Camp Far West Hydroelectric Facility. Camp Far West is a run‐of‐river hydroelectric facility with a capacity of 6.8 MW and will produce approximately 23,700 MWh of electricity per year. SVP is the sole off‐taker of this project’s output.

Calpine Geothermal
SVP entered into a long‐term PPA for renewable geothermal energy that will begin delivery energy to SVP in 2025. The PPA will allow the City of Santa Clara to receive clean, renewable energy produced from multiple Calpine geothermal power plants located in Sonoma and Lake Counties. It will deliver up to 50 MW of renewable energy during the period of 2025 to 2026 and, in 2027, the amount delivered will increase to 100 MW through 2036.

4.5. M‐S‐R Resources
Santa Clara, along with the Modesto Irrigation District and the City of Redding, is a member of the M‐S‐R PPA. The resources that are jointly owned, or procured through PPAs are described below:

M‐S‐R PPA Purchased Power – Big Horn Project I and II
In 2005, the M‐S‐R PPA entered a series of PPAs with Avangrid Renewables for the purchase of energy from the Big Horn I Project. Big Horn I is a 199.5‐MW wind project located near the town of Bickleton, WA.

Santa Clara receives 52.5% of the power purchased by the M‐S‐R PPA from Big Horn I, which equates to approximately 105 MW. Santa Clara uses a portion of its transfer capability of the California‐Oregon Transmission Project (COTP) to provide for the transmission of the output from the Big Horn I Project to the California‐Oregon border.

In 2010, the M‐S‐R PPA subsequently negotiated with Avangrid for the purchase of the output from a 50‐ MW expansion of Big Horn I, called the Big Horn II Project. Santa Clara receives 35% of the output from this project, or approximately 17.5 MW of project capacity.

4.6. Renewable Energy Strategy
A significant portion of the energy received by Santa Clara customersis generated from renewable energy resources. Santa Clara’s power mix in Calendar Year 2022 consisted of 34% eligible renewable resources.

When large hydroelectric resources are included, Santa Clara’s power mix consisted of 74% renewable and large hydroelectric power. On December 6, 2016, the Santa Clara City Council adopted revisions to Santa Clara’s Environmental Stewardship and RPS Policy Statement (Santa Clara Resolution 16‐8392), and adopted a new RPS Enforcement Program, to conform to the standards and timetable set forth in SBX1‐ 2, signed by the Governor on October 6, 2016.

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 Santa Clara satisfied the RPS target for Compliance Period 1 (from 2011 through 2013), with an average of approximately 20%of Santa Clara’s energy portfolio supplied from renewable resources over such period.
 Santa Clara satisfied the RPS target for Compliance Period 2 (from 2014 through 2016), meeting the compliance requirement of 20% of retail sales in 2014 and 2015, and 25%of retail sales in 2016.
 Santa Clara satisfied the RPS target for Compliance Period 3 (from 2017 through 2020), meeting the compliance requirement of 27%of retail sales in 2017, 29%of retail sales in 2018, 31%of retail sales in 2019, and 33%of retail sales in 2020.

Compliance Periods 1‐3 have been verified and approved by the State of California. In the first and second year of Compliance Period 4 (from 2021 through 2024), Santa Clara satisfied the RPS target, meeting the requirement of 35.75% of retails sales in 2021 and 38.5% of retail sales in 2022. Santa Clara expects to fulfill the Compliance Period 4 RPS requirement by procuring eligible renewable energy resources (excluding “large hydro”) amounting to 44% of total retail sales by 2024. SB 100 requires 60% eligible renewable energy compliance by December 31, 2030. Santa Clara is well positioned to meet the new renewable energy compliance requirements of SB 100.

Due to SVP’slong position in renewables, SVP will eithersell excessrenewable generation to other entities or accumulate RECs that exceed RPS requirements as excess procurement to be utilized in future years in case of unplanned curtailment, plant interruptions, and unexpected load growth, future project delays or as needed to ensure compliance with the RPS. Excess procurement allows SVP to evaluate additional eligible renewable resources projects, other generation and potential battery storage projects that will optimize the value for the customers. SVP starts new procurement processes for a forecasted need at a minimum 3‐5 years before the resource is needed. SVP is fully compliant with the State requirement that 65% of eligible renewables are under long term contracts.

4.7. Transmission and Distribution System Assets and Adequacy Santa Clara’s service area is surrounded by PG&E’s service area and the two systems are interconnected at two Santa Clara‐owned 115 kV receiving stations – Northern Receiving Station (NRS) and Kifer Receiving Station, each located within Santa Clara’s city limits. In addition, Santa Clara has a 230‐kV interconnection with PG&E at PG&E’s Los Esteros Substation (LES) in the City of San Jose. Power received at LES is transmitted by Santa Clara approximately six miles to NRS. Santa Clara owns facilities for the distribution of electric power within its city limits (approximately 18.4 square miles), which includes approximately 27 miles of 60 kV power lines, approximately 500 miles of 12 kV distribution lines (approximately 64% of which are underground), and 27 stations. Santa Clara’s electric system experiences approximately 0.5 to

1.5 hours of outage time per customer per year. This compares favorably with other utilities in California with reliability factors ranging from 1.0 to 2.5 hours outage per customer per year. To the extent Santa Clara requires additional transmission beyond its current transmission system limit, the city will need to advocate at the CAISO for additional transmission capability through the CAISO annual Transmission Planning Process (TPP) (See SVP Transmission Projects Below).

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NCPA Geysers Transmission Project
To meet certain obligations required of NCPA to secure transmission and other support services for the NCPA Geothermal Project, NCPA undertook the geysers transmission project (the Geysers Transmission Project). The Geysers Transmission Project includes (i) a co‐tenancy interest in PG&E’s 230 kV line from Castle Rock Junction in Sonoma County to the Lakeville Substation (the Castle Rock to Lakeville Line), (ii) additional firm transmission rightsin the Castle Rock to Lakeville Line and (iii) the Central Dispatch Facility.

Santa Clara has a 55 MW share in the Geysers Transmission Project, which provides a link from the Geysers to PG&E’s bulk transmission system.

TANC California–Oregon Transmission Project (COTP)
The Transmission Agency of Northern California (TANC) is a joint power agency established by a group of California publicly‐owned utilities in 1984. Its purpose was to plan, design and construct the California Oregon Transmission Project (COTP), a 240‐mile long, 500‐kilavolt (kV) alternating current (AC) transmission line between the California‐Oregon border and Central California. The COTP was completed and energized in 1993. Santa Clara is a member of the TANC and has an approximate 10% of TANC’s share of COTP transfer capability. Santa Clara is using a portion of its share of the project transfer capability of the COTP to provide transmission of energy generated from the Big Horn Projects.

TANC Tesla–Midway Transmission Service
TANC and certain TANC Members have arranged for PG&E to provide TANC and such TANC Members with 300 MW of firm, bi‐directional transmission capacity on its transmission system between PG&E’s Midway Substation and the electric systems of the TANC Members or the COTP (the Tesla‐Midway Service) under a long‐term agreement known as the South of Tesla Principles (SOTP). Santa Clara’s share of Tesla– Midway Transmission Service is 81 MW. Santa Clara utilizes its share of the TANC Tesla–Midway Transmission Service to provide access to power supplies located in the southwest.

SVP Transmission Projects
On September 6, 2022 SVP set a system peak load of 702 MW. With recent load growth of 5 to 7% and increasing industrial sector demand, SVP is looking to increase the capacity of its existing transmission system. Figure 14 presentsthe projects have been approved to increase the capacity or enhance reliability of the transmission system. Even with these additional transmission projects, the City of Santa Clara will face challenges to fully decarbonize by 2035 while also meeting its growing load requirements.

During the CAISO 2021‐2022 TPP, CAISO approved the development of two new 500 MW high voltage direct current (HVDC) lines in the South Bay area. One of those lines will connect from the Newark substation to Los Esteros substation and into SVP’s Northern Receiving Station while the other 500 MW line will connect from Metcalfsubstation to San Jose B substation. In March 2023, LS Power Grid California, LLC, was selected to finance, construct, own, operate and maintain these two new lines. The Newark‐ Northern Receiving Station line is anticipated to be in service in 2028.

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Figure 14. Current approved SVP Transmission Projects
Transmission and Distribution Upgrades/Replacements Identified and in Budget Cost (Million $)
60KV Breaker Upgrades  $3.10
Duane‐Scott 115kV $1.62
Esperanca Substation  $26.92
Fiber Development, Design, and Expansion $3.44
Homestead Substation Rebuild  $1.45
KRS Rebuild and Replacement $86.46
Northwest Loop Capacity Upgrade  $4.75
NRS Transformer and Breaker Upgrades $87.55
NRS‐KRS 115kV Line  $31.35
Operations and Planning Technology $1.61
Serra Substation Re‐Build  $0.22
South Loop Reconductor $18.61
SRS Rebuild and Replacement  $90.55
Storm Water Compliance $0.72
Substation Capital Maintenance and Betterments  $1.03
Substation Control and Communication System Replacement $0.14 Substation Physical Security Improvement  $0.23
System Capacity Expansion $3.35
Transmission and Distribution Capital Maintenance and Betterments  $9.44 Transmission Loop 1 $4.69
Transmission Loop 2  $2.00
Transmission System Reinforcements $0.40
Walsh‐Uranium 60kV Reconductor  $2.41
Total $382.02

4.8. Natural Gas Commodity, Transportation and Storage
SVP owns several gas‐fired power plants in its portfolio. Through the gas pre‐pay agreement described below, SVP aims to hedge the impact of gas supply and price volatility on its customers.

Natural gasisthe primary fuel and the primary variable operating cost of Santa Clara’s Gianera Generating Station, DVR Power Plant and the LEC. These plants can require delivery of up to 49,000 MMBtu per day fuel, with current average daily requirements of 24,400 MMBtu per day. Santa Clara has developed a comprehensive natural gas program to both manage supply and price volatility. This includes the procurement of a supply of natural gas at a discount from the monthly index price pursuant to a gas prepayment arrangement and several fixed price contracts for 10,000 MMBtu from 2020 to 2025.

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M‐S‐R Energy Authority – Gas Prepay
In 2009, Santa Clara participated in the M‐S‐R EA Gas Prepay Project. The Gas Prepay Project provides, through a Gas Supply Agreement between M‐S‐R EA and Santa Clara, for a secure and long‐term supply of natural gas of 7,500 MMBtu daily (or 2,730,500 MMBtu annually) through December 31, 2012, and 12,500 MMBtu daily (or 4,562,500 MMBtu annually) thereafter until September 30, 2039. The Gas Supply Agreement provides this supply at a discounted price below the monthly market index price (the PG&E Citygate index) over the 30‐year term.

4.9. Wholesale Energy Trading
For several years, Santa Clara has used its energy and transmission resources together with its power scheduling capabilities to buy and sell energy in the western North American market. As deregulation unfolded, a greater need to manage resources on a day‐to‐day basis evolved, resulting in a more comprehensive approach to trading operations at Santa Clara. The principal reason for wholesale power trading is to optimize the value of the utility’s assets and cost‐effectively serve its retail load. Since a substantial portion of Santa Clara’s energy needs are being met through contracts, SVP uses its energy, RA and transmission resources to buy and sell actively in five established wholesale power trading market zones: Mid‐Columbia (MID‐C), California‐Oregon Border (COB), North of Path 15 (NP15), South of Path 15 (SP15) and Palo Verde Hub. Trades may be directly with counterparties or through clearinghouses, such as the InterContinental Exchange (ICE).

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5.Customer Programs, Energy Efficiency and Demand
Response Resources

5.1. Energy Efficiency Program Background
Targets for energy efficiency programs (and established under PUC section 9505) are based on the estimated net market potential.14 The net market potential provides a forecast of market potential for specific utility energy efficiency programs. The net market potential is a subset of the total economic potential and technical potential and recognizes that not all impacts that are technically or economically achievable will be realized.

Santa Clara’s energy efficiency programs are separated into residential and non‐residential programs.

Total Public Benefits Charge (PBC) funds are about $16 million in fiscal year ending 2023. Residential programs include rate assistance for income‐qualified customers, energy efficiency rebates (heat pump water heaters, room air cleaners, pre‐owned EV rebates for income‐qualified customers and variable speed pool pumps), energy audits, an income‐qualified solar grant program and programs for schools and libraries. Non‐residential programs include energy audits, installation management assistance for small companies, rebates for a wide variety of equipment (lighting, air conditioning systems, chillers, motors, new construction, food service equipment and customized installations, etc.), energy efficiency grants for nonprofit organizations and Homeowners Associations, building electrification rebates and design and construction assistance.

The goals and objectives of the programs are as follows:
 Implement cost‐effective energy efficiency programs to lower energy use. The cost to implement energy efficiency programs should be lower than the capital cost to build new generation and benefits of the total programs should exceed costs under the Total Resource Cost test under the methodology reviewed and approved by the NCPA Demand Management Working Group, of which SVP is a member.
 Provide the public benefit programs in a manner that creates value to the community and meets all applicable legal requirements.
 Assist Divisions and City Departments in achieving optimal energy efficiency at City facilities and assist in implementing new energy related technologies for the benefit of Santa Clara and community.
14 CMUA, “2020 Energy Efficiency Potential Forecast” (Sacramento, CA: California Municipal Utilities Association, 2020), https://www.cmua.org/sb1037‐reports.

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 Implement programs to support renewable power generation that increase resource diversity and minimize adverse environmental impacts from electric generation and operation of the electric system.
 Support emerging technologies to speed up market acceptance therefore, allowing energy efficiency services and products to compete in the open market.  Assist income‐qualified residents in lowering their electric bills and in installing energy efficient appliances and other measures.
 Determine the best energy programs to offer Santa Clara customers by collecting input from community organizations, businesses, and other city departments.

SVP participated in the California Municipal Utilities Association (CMUA) Energy Efficiency Potential Forecasting Study. The most recent study was adopted by the Santa Clara City Council in 2021. Figure 15 presents the results of energy efficiency potential forecasting study.15 Figure 15. Forecasted Energy Efficiency Potential
Year Utility Specified
Feasible Goal (MWh)
2021 11,584
2022 11,536
2023 11,013
2024 10,604
2025 8,913
2026 7,305
2027 6,651
2028 5,808
2029 5,817
2030 5,372

5.2. Current Energy Efficiency and Building Electrification Initiatives SVP maintains a robust suite of energy efficiency programs that will contribute to the state’s goal of doubling statewide energy efficiency savings as codified in SB 350. Energy efficiency programs are intended to offer maximum benefit to the community while meeting all regulatory requirements. The regulatory requirements include the following:
 PUC 385 requires that the utilities collect and spend a percentage of their base retail electric revenues on qualified Public Benefits Programs. The customary amount collected by public utilities in California is a minimum 2.85%of annual base retail electric revenues. The funds must 15 CMUA.

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be spent on programs in four categories including energy efficiency, research and development, renewable energy resource development and income‐qualified assistance.  PUC 386 requires each local POU to ensure that income‐qualified families have access to affordable electricity, and the level of assistance reflects the level of need. Furthermore, utilities shall ensure that income‐qualified families have access to low‐cost, no‐cost measures that reduce energy consumption.
 PUC 454.5 and PUC 9615 both require utilities to address unmet resource needs through energy efficiency and demand response prior to procuring new sources of power.  PUC 9505 requires each local POU to annually report investments and achievements in energy efficiency and demand reduction programs. Furthermore, utilities must identify all potentially achievable cost‐effective electricity efficiency saving and report savings targets to the CEC.  Public Resources Code 25305.2 requires the CEC to report to the Legislature a comparison of the annual energy savings targets versus the actual energy efficiency savings and demand reduction for each local POU.
 Public Resources Code 25310 I(1) requires the CEC to set goals that will double statewide energy efficiency savings in California by 2030 and will require specific targets for SVP.

A comprehensive list of energy efficiency projects and programs under consideration is presented here.

New Programs for Fiscal Year 2023/2024 to 2028/2029
 Commercial Solar and/or Solar Plus Battery Storage Performance Incentive Program – This program will provide performance‐based incentives to commercial customers who install large solar plus battery storage systems to assist in reducing the coincident peak demand and/or assist in areas where electric transmission and distribution resources are constrained. A performance‐based incentive for installation of large solar systems may also be offered if there are significant grid benefits to SVP for installations without battery storage systems.  Nonprofit Solar Grant Program – As part of the commercial solar rebate initiative, funds have been designated to provide grants to nonprofit facilities in Santa Clara interested in installing a PV system at their facility. The grant allows a portion of the funding to be spent on roof repairs or replacement to make the facility ready for a PV system.  Municipal Energy Efficiency Project On‐Bill Financing Program – This program will provide on‐ bill financing for projects implemented at Santa Clara facilities where the city is the utility account holder and that meet all other requirements of SVP’s energy efficiency programs.

Projects must have a payback period not more than 5 years after rebates. Payments will be spread across utility bills based on the payback period, not to exceed 5 years. The intent of this Customer Programs, Energy Efficiency and Demand Response Resources2023 Integrated Resource Plan2023 Integrated Resource Plan
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program is to help Santa Clara city departments fund energy efficiency projects through utility bill savings.
 Scholarship Program for Income‐qualified Residents – This program will provide scholarships to customers who meet specified income requirements. Eligibility will be working age adults who enroll in a technical school or training program for a career that will support the energy industry.

Examples include but are not limited to HVAC technicians, solar system installers, utility line workers, etc. The intent of the program is to assist those with the lowest incomes to obtain the skills and certifications necessary to obtain higher paying jobs and to support workforce development in the energy industry or industries that support energy efficiency and building electrification programs.
 Income‐Qualified Used EV Rebate – This program will provide an incentive for income‐qualified customers to purchase a used EV or plug‐in hybrid EV. Incentives will be tiered to provide a higher incentive for an EV over a plug‐in hybrid and will include an equity component with a bonus incentive for those who qualify for the Low‐Income Home Energy Assistance Program. An additional bonus incentive may be included for vehicles meeting the specified minimum charging efficiency (kWh per 100 miles driven). Funding for past Income‐Qualified EV Rebates came from Low Carbon Fuel Standard Credit funding, and this program will be funded under the income‐qualified category of the Public Benefit Charge.

Ongoing Programs
 Residential Pool Pump Rebate – This program provides a rebate to residential customers installing a new variable speed pool pump with a qualifying controller.  Residential Heat Pump Electric Water Heater Rebate – SVP offers a rebate for the purchase of a qualified electric heat pump water heater with bonus incentives to income‐qualified customers.  Residential In‐Home Energy Audits, Education, and Hot Line: The program encourages residents to become more energy efficient and reduce their energy bills through home audits, online and in person classes, school programs and community outreach at events. Energy audits include free items to improve home weatherization where needed. This program also includes “Santa Clara could perhaps focus more on investing in
distributed solar in the near term.” ‐KJ, Santa Clara
resident
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support of the Santa Clara libraries and schools through donation of materials on the topics of energy efficiency and renewable energy for libraries and classrooms.  Tier II Advanced Power Strip Giveaway Program: SVP provides free Tier II Advanced Power Strips (APS) to income‐qualified customers and residents of multifamily apartment complexes. A Tier II APS is also included in the energy saving items provided during a home energy audit.  Tool Lending Library: This program provides tools and equipment to the Santa Clara libraries so they may be checked out to library patrons to assist in measuring energy consumption and installing energy efficient measures in their homes.
 Silicon Valley Power Marketplace: The Marketplace is an online marketplace where residential customers can purchase energy saving equipment and electric yard care equipment. Instant rebates are available on some types of equipment, with higher rebate levels available to income‐qualified customers. Shipping is free on all purchases over $50 and is a flat rate of $5 per order for all other orders.
 Residential Blower Door and Duct Testing Pilot Program: To help customers improve the efficiency and comfort of their homes through the reduction of leaks, this pilot program will be available to residential customers in single family homes who have central air conditioning. A free SVP audit will be required to determine if the home is a good candidate for the blower door test. Duct testing is a much more involved process and will be offered to those customers who are a good candidate for reducing the leaks in their air conditioning duct system, who demonstrate an interest in taking action to improve the duct work, and who are not already doing an air conditioning system upgrade where a duct test is required by building code. The service will be free to eligible customers under the pilot program. At the time of this report, this pilot program is still in the design phase and has not yet been launched.  Customer Directed Rebate – This program provides incentives based on actual energy saved for energy efficiency measures that do not fall into SVP’s standard business rebate programs. The program also includes a performance incentive option for projects where persistence savings is questionable.
 Data Center Efficiency Program – This program targets data centers with IT server load greater than 350 kW or cooling load greater than 100 tons. The incentive is paid as a performance incentive over multiple years.
 Commercial New Construction Rebate: This program provides a rebate to customers who exceed Title 24 by 10 percent for the measure being incentivized, in line with other prescriptive rebates for retrofit projects. A Design Team Incentive matching the Investor‐Owned Utilities program is provided.

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 Business Energy Audits: Provides free energy efficiency audits to business customers. Energy and Resource Solutions administers this and other business PBC programs.  Business Rebates: Encourages businesses to install energy efficient lighting, HVAC equipment, enhanced ventilation controls, food service equipment, etc. The programs are occasionally changed to match statewide programs.
 Small Business Efficiency Services Program – This program is targeted at small business customers, and aids in identifying energy efficiency projects, selecting and managing contractors, and help with filling out rebate application paperwork. The program also provides a 35%incentive for lighting and HVAC rebates, if customers to install the lighting measures within 6 months of program enrollment and HVAC measures within 12 months of enrollment in order to receive the additional incentive.
 Energy Efficiency Grant for Nonprofit Organizations: This program provides grants to non‐profit organizations to improve the energy efficiency of their facilities.  Building Operator Certification Training Scholarships: This program provides scholarships to building operators responsible for facilities in Santa Clara who meet the Building Operator Certification Training Program’s prerequisites. The coursework helps customers identify energy efficiency opportunities within their facilities, which can lead to energy efficiency project implementation.
 Energy Efficiency Grant for Homeowners Associations: This program provides a grant for Homeowners Associations to upgrade to more energy efficient equipment in the common areas of their communities.
 Community Outreach Grants for Energy Efficiency and Building Electrification Education: This program provides an opportunity for nonprofits and community‐based organizations to receive a grant up to $10,000 to promote energy efficiency and building electrification benefits within our community. A focus on traditionally underserved communities or diversity, equity and inclusion is required.
 Student Grants for Energy Efficiency and Renewable Energy Projects or Awareness Campaigns:

SVP offers grants up to $5,000 for high school students to create projects or awareness campaigns that will educate the Santa Clara community about energy efficiency and/or renewable energy. Examples include but are not limited to educational videos, public art displays, online resources, outreach materials, demonstration projects, webinars, or workshops.  Controls Program: This program is available for projects where at least 80% of the savings come from the control strategies. Incentives are paid on a performance basis over 5 years.

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 Building Optimization Rebate: For buildings with HVAC systems controlled by building automation systems, a rebate is provided for reprogramming the control system to optimize HVAC performance. Typically, this involves conducting an energy assessment that provides an implementation plan for testing and making control system improvements that optimize HVAC operation.
 Public Facilities’ Energy Efficiency Program:  SVP provides technical assistance and financial incentives for the expansion, remodel, and new construction of Santa Clara buildings. Included in this program are higher levels of rebates for qualifying equipment and energy management assistance.

Third Party Programs for Business Customers
As one of the ways to enhance energy savings through the PBC programs and meet kilowatt hour and kilowatt demand reduction goals, SVP periodically embarks on an Request for Proposal process to add third party energy efficiency programs to its Public Benefit Program offering. Of the responses received each cycle, a review team selects responses that are both cost‐effective and the most likely to help customers without overlapping with programs already being provided. The last Request for Proposal was issued in April 2018 and all selected programs have ended. An Request for Proposal is currently in process.

Complementary Programs
 Income‐Qualified Programs:
o Financial Rate Assistance Program: SVP’s income‐qualified programs include a Rate Assistance Program, where income‐qualified customers receive a 25% discount on their electric bill.
o Income‐Qualified EV Charging Station Grant for Multi‐family Properties: Under its income‐qualified programs, SVP offers a grant of up to $1,000 per charging station for multi‐family properties where a specified percentage of customers residing at the property qualify for SVP’s income‐qualified programs. This is in addition to the rebate program the utility offers to all multifamily complexes in Santa Clara.  Medical Assistance Programs
o Medical Rate Assistance Program: Customers receive a 25% discount on their electric bill if they qualify due to high electric use for medical reasons. The programs are managed in‐house.
 Research, Development, and Demonstration:

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o Emerging Technologies Grant: This program encourages businesses to demonstrate new products and product applications not yet commercially viable in today’s marketplace, install energy efficient technologies not generally known or widely accepted, yet show potential for successful market growth, successfully apply energy efficiency solutions in new ways, or introduce energy efficiency into industries or businesses that are resistant to adopting new technologies or practices.
o APPA DEED Program: SVP is a paying member of the American Public Power Association (APPA) Demonstration of Energy & Efficiency Developments (DEED). This program funds grants, internships and student scholarships to further R&D in the electric utility industry and support innovative applications of energy efficient or renewable technologies. Over the years, SVP has applied for and received several DEED grants.

Most recently, SVP has received grants for additional research of ductless mini split HVAC units and for commercial food preparation appliance energy savings. o California Lighting Technology Center (CLTC): SVP provides financial support to the CLTC to further research and testing of emerging lighting technologies.  Building Electrification Programs:
o Heat Pump Water Heater Electrification Program: SVP provides funding for a regional midstream heat pump water heater electrification program through BayREN where enrolled contractors receive a $1000 incentive for installing an electric heat pump water heater in place of a natural gas water heater. SVP pays an additional incentive to income‐qualified customers.
o Multifamily Boiler Electrification Pilot Program:  This program provides up to $100,000 in funding for the conversion of a natural gas boiler to an electric boiler at multifamily complexes with at least 25 dwelling units. The program covers up to 100% of the incremental cost of replacing the gas boiler with an efficient boiler. o Smart Electric Panel Upgrade Rebates: SVP provides a rebate to residential customers who upgrade their electric panel to a smart panel and install circuits for both an EV charger and an appliance converted from natural gas to electricity. A bonus incentive is available to income‐qualified customers.
o Commercial Electrification Incentives: SVP provides bonus incentives for the electrification of efficient food service equipment. Incentives are also available for heat pump water heaters, heat recovery chillers, heat pump pool heaters and heat pump air conditioners. The utility also offers a Customer Directed Electrification Rebate that pays Customer Programs, Energy Efficiency and Demand Response Resources2023 Integrated Resource Plan2023 Integrated Resource Plan
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an incentive based on measured and verified energy savings for any building electrification project that does not fall within its standard electrification rebates. o Induction Cooking Demonstration Project: SVP retrofitted the Santa Clara Unified School District’s Adult Education cooking classroom with induction cooktops and new cookware. The utility sponsors classes once or twice per month for residents to learn to cook new cuisine while trying out an induction cooktop. Adult Education cooking instructors were provided with training on the benefits of induction cooktops and lessons they can teach to demonstrate the benefits. Handouts are also provided to all program participants.

Ending Programs
 Residential Electric Dryer Rebate – This program provided a rebate for ENERGY STAR‐qualified electric clothes dryers that meet the minimum Combined Energy Factor rating. Due to low energy savings that can be claimed, this program ended June 30, 2023.  Variable Frequency Drive Air Compressor Rebate – This measure is for Variable Frequency Drives on rotary screw air compressors of 5hp – less than 25hp, as the energy code requires Variable Frequency Drives on compressors of 25hp or greater. Following customer outreach for this program, we found very little potential within Santa Clara, so this program was retired on June 30, 2023. If a customer has a qualifying air compressor and would like to install a Variable Frequency Drive, an incentive can be provided under the Customer Directed Rebate program.

5.3. Storage
In 2013, AB2514 codified Public Utilities Code Section 2836(B) that requires the governing board of each local publicly owned electric utility (POU) to determine appropriate targetsfor the utility to procure viable and cost‐effective energy storage systemsto be achieved by December 31, 2016, and December 31, 2020, on or before October 1, 2014, as part of their supply plan. There are no requirements for POUs to set future targets for energy storage. The statute also requires each governing board to re‐evaluate the determinations made pursuant to this subdivision not less than once every three years, where the first three‐year period ended in 2017, and the second evaluation period ended December 31, 2020. All future updates are now included in the IRP process.

In 2017, SVP determined that energy storage was not cost‐effective, therefore, did not pursue energy storage targets. At the time, SVP analyzed three potential Research and Development pilot projects at the transmission, distribution point‐of‐interconnections, and behind‐the‐customer meter and provided updates in the 2020 AB2514 submittal to the CEC, Docket Number 20‐MISC‐01 TN# 235878). In 2020, SVP had four on‐going pilot projects that were to be commercially operational from 2021 through 2023. What was unanticipated was the supply chain issues that arose during the COVID pandemic and the price Customer Programs, Energy Efficiency and Demand Response Resources2023 Integrated Resource Plan2023 Integrated Resource Plan
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escalation of Lithium that changed the economics of battery storage projects (Figure 16). Updates on these projects are included in this plan.

Figure 16. Lithium Price ($/lbs) 2019‐202316
Current Utility‐Scale Energy Storage Projects
SVP is currently contracting with a third party to build and operate up to a 50 MW 4‐hour (200 MWh) utility‐scale lithium‐ion BESS within SVP’s service territory. This contract will allow SVP to be the beneficiary of the BESS for a twenty‐year term with an option to extend it for an additional five years. The BESS will participate in the CAISO market and will have the capability of performing intraday energy arbitrage by charging the BESS when market prices are low (buying the energy from the CAISO market) and discharging the BESS when market prices are high (selling the energy into the CAISO market) and capturing the difference between these prices. Typically, the BESS will charge when there is surplus renewable electricity on the CAISO grid. The BESS will also be able to help control voltage and frequency.

Using the BESS may help integrate renewables, reduce dependence on gas‐fired generation, and reduce GHG and criteria air pollutant emissions in Santa Clara. The BESS will also qualify as a resource adequacy resource and can be used to meet SVP’s RA requirements along with the otherresourcesin SVP’s portfolio.

The BESS project is expected to be in commercial operation in late‐2025.

Current Microgrid Projects
SVP was developing two Renewable Energy Microgrids to support two City of Santa Clara Fire Stations for up to four hours of run‐time providing back‐up power during grid outages. SVP studied the feasibility of meeting and exceeding 6‐8 hours long‐duration run‐times for the energy storage systems. SVP is 16  Daily Metal Price: Lithium Price. https://www.dailymetalprice.com/metalpricecharts.php?c=li&u=lb&d=1200 Customer Programs, Energy Efficiency and Demand Response Resources2023 Integrated Resource Plan2023 Integrated Resource Plan
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partnering with the Fire Department to prioritize Fire Station #1 , and Fire Station #2 with the potential to co‐locate the microgrid at Fire Station #2with co‐located public sites to enable a community microgrid concept. Due to increased costs, the microgrid project at Fire Station #1 is no longer feasible. Only Fire Station #2 is moving forward but has been combined to include more structures like the Emergency Operations Center for the City of Santa Clara. The project will demonstrate the installation of solar and storage and potentially EVs, integrated with smart microgrid components. The microgrids willsupport the research, design, deployment, and operations of a microgrid through the implementation of advanced energy management controller/software, load control, for standby power, energy and capacity and test feasibility to serve grid ancillary services. This project will also pilot an SVP specific engineered switch to enable future microgrids to interconnect with the SVP grid in the future. The design was a result of a previous data center pilot that SVP had to cancel.

SVP is piloting microgrid concept to create more redundancy in its grid, enable the detection of outages and faults on the grid, to prevent outages, and power quality events. The microgrid automatically responds to a grid outage by islanding. The microgrid remains in island mode supporting the Fire Station and auxiliary load until a resynchronization command isissued. This allowsthe microgrid to autonomously support the islanded loads during grid outages and then automatically resynchronize and resume grid connection upon restoration of normal grid voltage and frequency. Additionally, built‐in software will perform an analysis of the microgrid components to detect equipment and process inefficiencies.

SVP will be receiving $500,000 in Federal funding to help bring the project on‐line. SVP will also be exploring funding through the California Electricity Backup Assets Program when it launched later in 2023 or early 2024. The project is targeted to be commercially online in 2025.

Customer‐Sited Battery Storage and Solar Power Purchase Agreement SVP partnered with one of its commercial customers on a 2 MW/4MWh behind‐the‐meter battery energy storage system, charged for the most part from on‐site PV solar generation. The battery will be cycled daily to increase renewable energy consumption from the on‐site solar PV system, while also being discharged, to reduce run‐times for natural gas generation dispatch during the evening peak. Commercial operation of the solar PV and battery storage system was originally planned for October 2021 but due to cost increases and supply chain delays the new target is 2024.

Data Center Battery Storage Project
In 2018, SVP was awarded a grant of $300,000 from the Bay Area Air Quality Management District to implement a behind‐the‐meter lithium‐ion battery storage pilot project. SVP has partnered with a battery equipment manufacturer and a data center to pilot a demonstration project. The project was cancelled in 2022 due to the doubling of the project costs, from $2.5M to $5M. What was salvaged out of the four‐ year project was the engineering design of a specific switch that allows for easy “plug‐in” of future microgrids. Thisswitch is projected to be utilized in the Fire Station Microgrid project (previously detailed).

The project was to demonstrate the use‐case for lithium‐ion batteries as longer‐duration uninterruptible power supply for data centers that are instantaneous and reliable, delaying or avoiding the use of diesel generators as backup power. Additionally, the pilot will demonstrate the economic viability and flexibility Customer Programs, Energy Efficiency and Demand Response Resources2023 Integrated Resource Plan2023 Integrated Resource Plan
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of a 2 MW/4 MWh battery energy storage system (BESS) that can be simultaneously dispatched at 2 MW capacity to support critical loads during a power quality event or outage. The main target was to reduce GHG and particulate matter, with a focus on vulnerable communities.

Residential Distributed Energy Resources Resilience and Equity Program In 2019, SVP joined three community‐choice aggregators (CCAs), East Bay Community Energy, Silicon Valley Clean Energy, and Peninsula Clean Energy in the release of a joint request for proposal for Resource Adequacy and load modification capacity to reduce SVP’s system and CAISO coincident peak. SVP requested a total of 0.7 MW for the residentialsector, and 2 MW for the commercial and industrialsectors.

SVP’s Residential Distributed Energy Resources (DER) Resilience and Equity program was meant to operationalize a fleet of residential PV‐paired battery systems as a peak shaving instrument and also to increase renewables and reduce GHG emissions in the most vulnerable communities through a virtual power plant concept. The program would prioritize customer segments including income‐qualified, medical baseline, and the disadvantaged communities. Additionally, the program intended to mitigate localized grid congestion and provide back‐up power during grid outages or PG&E’s Public Safety Power Shutoff events. The program would also evaluate installations at single‐family homes and multi‐unit dwellings.

In 2021, the selected vendor decided that SVP was not a big enough market and noted that our residential pricing structure is not high enough to make the venture work out economically SVP will re‐evaluate a new residential program in the future.

Green Lots – Tasman Drive Parking Structure
SVP completed a pilot energy storage project at the Tasman Drive Parking Structure with the intent to reduce customer‐side peak demand charges due to high energy consumption from EV level 2 and Direct Current (DC) fast charging. Green Charge Networks, a Santa Clara based energy storage company, approached SVP to install a 30 kW “GreenStation” battery energy storage system along with an EV DC fast charger station at this location. The cost of the energy storage system, the DC fast charger and the installation was covered by a CEC grant program, resulting in no costs to the City of Santa Clara or SVP.

The pilot ended in 2018, and through the monitoring of the EV Charging Station patterns, the pilotresulted in an increased usage of the EV charging stations from 2015 through 2018. It was concluded that given the large station count (49 in total), power demand isstill peaking at a small fraction of the system capacity (under 17% forthe 30‐day period from February 19, 2018 to March 21, 2018). The GreenStation isinstalled behind‐the‐meter and dampens the demand spikes that occur when the DC fast charging station is used, therefore reducing the operating costsfor the City’s Streets Department due to the management ofspikes to avoid an increase in demand charges. The battery was decommissioned and removed in 2023.

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Looking Forward
In the next five to ten years, SVP plans to focus its research on the deployment of energy storage projects and to develop localized system integration studies to determine locational nodes in SVP’s service territory to alleviate congestion and to manage energy and capacity needs as well as maintaining balance of its grid. Other variables will also impact scalability and the use‐case for storage, including, SVP’s load growth, increased behind‐the‐meter customer distributed energy resources, electric vehicles, and building electrification. The deployment of storage will help SVP meet on‐going State and City‐wide renewable energy and sustainability goals and targets.

SVP plans to research the potential to participate in the CAISO wholesale market, including participating in the non‐generator resource, regulation energy market, and proxy demand response participation models, which include not only bidding energy resources, but also ancillary services(frequency regulation, spin, non‐spin).

To manage, operate, and monitor performance, SVP intends to research an architecture that integrates each of its pilot programs into a distributed energy resources management platform, tied to additional microgrid sites. The purpose is to enhance coordination amongst DERs, dispatch, and communication across DER assets connected to the grid to optimize reliability, safety and efficiency when operating the distribution grid.

SVP believes that commercially available long‐duration technologies tied to clean fuel sources that can be stored on‐site will be required to transform adoption at the utility‐scale level. SVP and its customers must have confidence that there is no interruption to the electric or gassupply if on‐site fuel cannot be achieved, otherwise storage fuel must be dense enough to store on‐site. Further, SVP anticipates that more demonstration projects from utilities and utility‐customer partnerships will be required to test end‐use applications, monitor stacked benefits, and to help scale the technology. Grant funding along with the decrease in energy storage costs will be needed to assist in bringing down the total installed costs of the systems. Additional federal, state, and local incentives and grants can encourage investment to scale the technology and test various end‐use applications.

Lastly, SVP will continue to benchmark new storage technologies, assessscalability and cost‐effectiveness, and pilot new programs/projects that foster a diverse set of clean, hybrid and long‐duration energy storage technologies. Because the City of Santa Clara is approximately 18.4 square miles, new storage technologies sited within the city’s boundaries must be energy dense to accommodate space constraints.

5.4. Transportation Electrification
Transportation electrification and zero‐emission vehicle (ZEV) policies have been gaining momentum in recent years, both at the state and federal levels. California has been a leader in this movement, with its Zero‐Emission Vehicle Program that requires automakers to produce a certain number of EVs each year.

The state has also set a goal to have 5 million ZEVs on the road by 2030.

At the federal level, the Biden administration has set a goal of reaching net‐zero emissions by 2050 and has proposed investing $174 billion in EV infrastructure, including charging stations and incentives for consumers to buy Evs. The most significant legislation to accelerate transportation electrification in U.S.

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history was the Inflation Reduction Act (IRA) of 2022, which was signed into law on August 16. The IRA introduced several significant changes to the tax credit for new Evs and the reforms to the $7,500 tax credit for Evs will evolve considerably over the coming months and years. The IRA also established tax credits for pre‐owned clean vehicles and for commercial clean vehicles.

California calls for a 40% reduction in GHG emissions from 1990 levels by 2030 and an 80% reduction by 2050 per Executive Order S‐3‐05 (2005). Air quality goalsinclude a 90% reduction in emissions of Nox from 2010 levels by 2032. In January 2018, Governor’s Executive Order B‐48‐18 set a goal of 5 million ZEVs on California roads by 2030 and directs state agencies to accelerate deployment of 250,000 chargers (including 10,000 direct current fast chargers (DCFCs) by 2025). SB 350 requires state agencies to identify recommendations on how to increase access to zero‐emission and near‐zero‐emission transportation options to income‐qualified customers. In December 2018, CARB passed the “Innovative Clean Transit” policy stating that by 2023, one quarter of purchased transit buses need to be zero emission, and by 2029, 100% of new buses purchased need to be zero emission. Governor’s Executive Order B‐55‐18 directs state agencies to work together to support the deployment of ZEVs in California, including through the development of infrastructure and incentives. Most recently in 2020, Governor’s Executive Order N‐79‐ 20 set a goal of transitioning all new passenger cars and trucks sold in California to ZEVs with the share of VEZ and plug‐in hybrid electric vehicles (PHEV) to reach 100% of new vehicle sales by 2035. CARB codified the Governor’s EO N‐79‐20 for light‐duty passenger vehicles with the adoption of the Advanced Clean Cars II rule that established a year‐by‐year roadmap for the share of VEZ to reach 100% of new vehicle sales by 2035.

One of California’s most important policies is the Zero‐Emission Vehicle Program, which requires automakers to produce a certain number of ZEVs each year. The program was first implemented in 1990 and has since been updated several times. In 2020, the state adopted new regulations that require automakers to sell an increasing percentage of ZEVs each year. By 2025, automakers must sell enough ZEVs to account for 8% of their total sales in the state. In addition, the Advanced Clean Trucks (ACT) Regulation requires manufacturers of medium‐ and heavy‐duty vehicles to sell a certain percentage of zero‐emission trucks in California, starting in 2024. SVP aims to prepare Santa Clara for success as new clean fleet requirements are set by the state. In April 2023, the CARB adopted the Advanced Clean Fleets regulation that requires beginning January 1, 2024, 50% of State and Local Government Agency Fleets annual vehicle purchases per calendar year to be zero‐emissions, and beginning January 1, 2027, that 100%of vehicle purchases to be zero‐emissions.

California has also implemented several financial incentives to encourage consumers to buy ZEVs. The state offers rebates of up to $7,000 for the purchase or lease of a new EV, and there are also federal tax credits available. Additionally, California allows ZEVs to use carpool lanes regardless of how many passengers are in the vehicle, providing an added incentive for drivers. In 2020, SVP along with other California electric utilities teamed up with CARB to offer the California Clean Fuel Reward, a point‐of‐sale price reduction of up to $1,500 for the purchase or lease of any eligible new Battery Electric or Plug‐in Hybrid vehicle. As of 2023, the reward amount has temporarily been reduced to zero and SVP is engaging with program stakeholders on the future strategy of the program.

To support the increased adoption of ZEVs, California has also invested heavily in charging infrastructure.

The AB 2127 Electric Vehicle Charging Infrastructure Assessmentfound that for passenger vehicle charging Customer Programs, Energy Efficiency and Demand Response Resources2023 Integrated Resource Plan2023 Integrated Resource Plan
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in 2030, over 700,000 public and shared private chargers are needed to support 5 million ZEVs, and nearly

1.2 million chargers to support about 8 million ZEVs anticipated under Executive Order N‐79‐20. An additional 157,000 chargers are needed to support 180,000 medium‐ and heavy‐duty vehicles anticipated for 2030.

Local Government Regulatory Landscape
SVP encourages the use of Evs as a part of our commitment to reduce carbon emissions. With convenient and publicly accessible EV charging stations, residents and business can help accelerate the efforts. Since 2019, Santa Clara has initiated a suite of Council actions, policies, and strategies to be an EV ready community by 2030.
 May 2019 – Adopted a Green Fleet Policy
 June 2019 – Adopted the EV Ready Community Blueprint
 April 2020‐ City Council approves a Public and Fleet Infrastructure Access Project  January 2021‐ City of Santa Clara Fleet Electrification Plan  September 2022‐ City Adopted All‐Electric Reach Codes SVP designed and built a robust and accessible EV charging infrastructure that maximizes the number of residents and visitors served. SVP has added over 100 EV charging connectors throughout Santa Clara’s 18 square miles in parks, community centers and other public access areas near multifamily housing; providing an amenity that increased park utilization and access to EV charging to residents who may not have access to charging at home.

SVP has also helped Santa Clara reduce its fleet operational costs and environmental impact by replacing Santa Clara‐owned old combustion vehicles with all‐electric vehicles. SVP purchased 46 all‐electric vehicles and an electric forklift to support Police, Fire, Public Works and other City department fleets in fiscal year 2022. Santa Clara will receive the benefits of lower operating and maintenance costs EVs provide as well as a reduction in smog and GHG emissions from operating their vehicle fleet.

In parallel with purchasing cleaner vehicles for Santa Clara, SVP also installed EV charging stations at City facilities to support the new clean fleet. SVP took a holistic approach using design thinking by partnering early with other City departments to select optimal locations and helped streamline the permitting process for future EV charging projects. SVP also explored enhancing projects with faster charging times and additional resiliency by adding renewable solar PVs plus storage. By Q3 2023, SVP energized nearly 50 additional charging ports at 8 locations supporting public and fleet charging and plans the next phase of EV charger installations to prepare for the City’s incoming medium and heavy‐duty fleet.

Using CARB’s Clean Vehicle Rebate Project (CVRP), which began tracking rebates for purchased ZEVs in 2011 through 2022, 2,764 battery‐electric, 910 plug‐in hybrids, 99 fuel cell, and 5 categorized as other vehicle rebates have been distributed for a total of 3,778 clean vehicle rebates registered within Santa Clara. Note that not all plug‐in hybrid, all‐battery, and fuel cell EVs sold/leased in the state are captured in this database. Not every eligible vehicle owner applies to the CVRP, and not every clean vehicle is Customer Programs, Energy Efficiency and Demand Response Resources2023 Integrated Resource Plan2023 Integrated Resource Plan
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eligible for the rebate. Over the first five years of the program, owners of about 75% of eligible vehicles participated in the rebate project. Department of Motor Vehicle (DMV) registration data is a preferred source for a more accurate estimate of current Plug‐in Electric Vehicle (PEV) adoption within a city; that data can also provide information on vehicle class for commercial vehicles. However, neither of these sources forecast vehicle ownership trends or inflow of traffic from surrounding areas. SVP requested registration data from the DMV on a bi‐annual basis beginning 2023 to support SVP’s energy procurement, transmission, and distribution planning for transportation electrification. In partnership with other northern California municipal utilities, SVP is actively coordinating with the DMV to establish a registration data sharing protocol that would enable data collection on a more frequent cadence. As Californians adopt more hybrid electric and alternative fuel vehicles, we are working on a transportation electrification strategy to prepare their electrical distribution grid for the future demands. SVP is also exploring managed charging programs using vehicle telematics to coordinate the customer side of the meter with the utility’s side, optimizing critical assets throughout the distribution network. In addition to shifting charging to times of day when there is more renewable energy supply on the grid, managed charging programs can also defer costly upgradesto distribution grid assets. SVP is also exploring fleet advisory program offerings such as online fleet planning tools and technical assistance for fleet customers in our service territory.

SVP also utilizes CEC new ZEV sales data which is updated on a quarterly basis by examining the DMV Vehicle Registration database to track vehicle adoption in Santa Clara. By the end of June 2023, the CEC reported a cumulative total of 8,824 all‐electric vehicles, 2,596 plug‐in hybrid EVs, and 140 hydrogen fuel cell vehicles in Santa Clara as shown in Figure 17.

Figure 17. New Zero Emission Vehicle Sales by year: Santa Clara Figure 18 showsthe cumulative growth of ZEV rebates dollars distributed though the CVRP program within SVP’s service territory, by vehicle type, from 2011‐2023. The slight decline in annual rebates in 2019 was Customer Programs, Energy Efficiency and Demand Response Resources2023 Integrated Resource Plan2023 Integrated Resource Plan
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due to popular rebate‐eligible vehicles. Reaching 200,000 sold in the U.S. and thus no longer qualifying for the federal PEV rebates. The IRA of 2022 changed the rules for the federal tax credit for vehicles purchased from 2023 to 2032 which made certain vehicles eligible again. The decline was further exacerbated by the Covid‐19 pandemic which unfolded in early 2020 and imposed global lockdowns leading to an unprecedented drop in car sales. Despite gradual recovery over the following year, the ZEV market also suffered from a rippling effect of global supply chain issues limiting vehicle availability.

Figure 18. CVRP Rebate Dollars in SVP Service Territory by year Figure 19. Cumulative SVP ZEV Rebates by ZEV Type, 2011‐2018 Rebates and Rebate Funding Issued or Approved to Date
Battery Electric Vehicle 2,869 $7,304,362
Plug‐in Hybrid Electric Vehicle 912 $1388,284
Fuel‐cell Electric Vehicle 105 $522,500
Other 5 $4,200
Total 3891 $9,219,346
For the SVP service area, EV forecast involves a significant increase in the number of vehicles through 2026. Figure 20 shows the cumulative number of EVs, including EVs and PEVs that are projected to increase from approximately 2,200 in 2018 to more than 24,000 by 2030 based on the CEC EV model.

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Figure 20. CEC Projected EV Adoption (cumulative)
SVP EV Readiness by 2030
In December 2017, the CEC released a Grant Funding Opportunity (GFO‐17‐604) for EV Ready Communities Challenge Phase I – Blueprint Plan Development.

On May 9, 2018, at the CEC Business Meeting, SVP was officially awarded a grant to develop an EV Ready Communities Blueprint. SVP, along with various Santa Clara city departments and stakeholders, has completed and developed the Electric Vehicle Ready Communities Blueprint (EV Blueprint) for Santa Clara per the grant requirements. The EV Blueprint identifies the actions and milestones needed to proceed toward implementation of an EV ready community through 2030. When the CEC solicited Phase II of the grant funding in 2020, SVP used the EV Blueprint as a submission for the application but unfortunately was not awarded Phase II funding. The EV Blueprint for Santa Clara defined goals and requirements, analyzed target areas, provided technical recommendations, and economic recommendations for charging infrastructure; and evaluated city programsto be implemented. The EV Blueprint also forecasted the number of PEV adoptions which included both person and commercial vehicles. Recognizing the inherent uncertainty in any forecast, and especially in nascent technology, the EV Blueprint Team developed three forecast cases: low, base, and high. The base case was based on SVP’s 2018 IRP using the “2017 SB 350 Common Assumptions Guidelines for Transportation Electrification Analysis.” To place that forecast in context, the EV Blueprint Team set a low case assuming no further PEV adoption and a high case based on Siemens proprietary PEV adoption forecasting tool, which resulted in adoption rates closely aligned with California’s statewide five million ZEV goal by 2030. Figure 21 shows the number of PEVs and required charge connectors forecasted for each of the adoption scenarios.

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Figure 21. Forecasted Plug‐in Vehicles and Charging Requirements, Cumulative – Santa Clara Source: SVP 2019 EV Readiness Blueprint
Current Electric Vehicle Charge Connectors
By 2022, Santa Clara and its businesses had installed 753 Level 2 charging connectors and 39 DCFC charging connectors. Note that a typical charging station contains multiple charging connectors to plug into multiple vehicles. In Santa Clara, the average charging station has six charging connectors. Using the Alternative Fuels Data Center (AFDC), Santa Clara tracks installation of public and private charge connectors.17  This information, as well as ownership type, is detailed in Figure 22.

Figure 22. Current Charger Port Installations by Type and Ownership18 EV Ownership Type EV Level 2 EVSE EV DC Fast
Private 47 0
Public 726 39
Total 773 39
The 812 public and private charge ports currently within Santa Clara are found in 340 different locations, for an average of 2.4 charge ports per location. However, specifically for DCFC, there are only one or two charge ports per location. Figure 23 maps where PEV chargers are located within Santa Clara, based on city permitting data. Most of the charging infrastructure is in the northern part of Santa Clara, zip code 95054, with 83% of all charge ports. Figure 24 details the distribution of EV chargers in Santa Clara by ownership, charger level, and location relative to the CalEPA SB 535 designated disadvantaged communities (DAC) area and the Justice 40 Initiative criteria area. Santa Clara currently has a total of 113 17 U.S. DOE, “Electric Vehicle Charging Station Locations,” U.S. Department of Energy, Alternative Fuels Data Center, 2023, https://afdc.energy.gov/fuels/electricity_locations.html#/find/nearest?fuel=ELEC. 18 U.S. DOE.

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city‐installed Level 2 public charging portslocated at Libraries, Community Recreation Centers, Santa Clara Convention Center, Tasman Garage, City Hall, and Parks. Two DCFC ports at the Central Park Library and the Santa Clara Convention Center have been identified for replacement. Figure 23 maps where PEV chargers are located within Santa Clara, based on city permitting data.

Figure 23. Map of PEV known Chargers within Santa Clara 19 19 Source: SVP Geographic Information Systems Team
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Figure 24. EV Charger Distributions by Santa Clara Zip Codes Grid Impacts of EV Adoption
SVP’s primary responsibility is to provide safe, reliable power, while limiting future cost increases and complying with city core values. PEV adoption poses both risks and opportunities to utilities as summarized in Figure 25. Since SVP’s electricity sales are primarily commercial/industrial, its energy use and peak demand profile is relatively flat monthly. However, SVP has historically experienced sudden increases in electricity demand at times, as customers move into new facilities. Data center loading can cause SVP’s load growth profile to be “lumpy”, due to new connections of substantial blocks of power‐ consuming facilities or equipment by industrial customers. This profile is reflective of the high intensity of industrial energy use in SVP’s service area, which is heavily weighted toward high‐technology manufacturing and data management facilities. To accurately plan impacts of PEV adoption on the grid, the SVP  EV Blueprint Team first gathered data on The City forecasted energy demand for electricity then identified the utility risks and opportunities from PEV adoption.

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Figure 25. Utility Risks and Opportunities from PEV Adoption20 Unlike many cities, which experienced lower than expected load growth due to energy efficiency programs, and DER, Santa Clara is experiencing consistent growth in energy and peak demand. Both energy and peak demand have been consistently increasing over the years and this trend is forecasted to continue going forward. The current forecast for PEV energy demand by 2030 is an additional 52 GWh to 143 GWh based on preliminary modeling. Overall, anywhere from a 0.70% to 2.61% of SVP’s total load demand.

SVP conducts Forward System Planning on an annual basisthrough a System Impact Study process, where load estimation from various SVP departments is incorporated into a set of unified planning input assumptions and studied under a variety of Planning Scenarios. The outcomes of the System Impact Study process are the determination of system constraints along with an assessment of mitigation options (Operationally, or Capital Improvement Project – CIP based) and associated costs. The Public Facing case is submitted annually to the CEC IEPR and CAISO Transmission Planning Process (TPP). For CY2023 TPP 24/25 SVP System EV Load Impacts will be studied as part of our annual System Impact Study process for the first time internally under a sensitivity scenario.

SVP also plans to conduct a 20‐Year Forecast beginning Q3‐Q4 2023 that will include a Spatial Analysis of Light, Medium and Heavy EVs and identify where the load will materialize on SVP’s system via Santa Clara city geographic information system (GIS) parcel map (each parcel assigned to a feeder). SVP will also identify requirements to manage EV growth (including sensitivities for both known & unknown load growth). In addition, SVP plans to update its 2019 EV Readiness Community Blueprint and develop a comprehensive Equity Focused Transportation and Building Electrification Plan. The primary purpose of the EV Blueprint was to develop a program of initiatives the City of Santa Clara could lead to support increased EV adoption and the many benefits which derive from that adoption. The plan update should 20 Source: SVP EV Ready Communities Blueprint 2019
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expand on that initiative to include the equitable transition to electrify both transportation and built environment. The Equity Focused Transportation and Building Electrification Plan development process should establish a firm planning foundation that involves engaging internal and external stakeholders, analyzing the current state of transportation and building electrification, forecast long‐term impacts of Plug‐in Electric Vehicle (PEV) and building electrification adoption, and prioritize key requirements to help Santa Clara meet greenhouse gas emissions reduction targets as identified in the City’s 2022 Climate Action Plan. The plan shall develop supporting analysis for multiple electrification scenarios in its forecasting and provide recommendations that provide Santa Clara with a clear understanding of the technical and economical requirements to support EV and building electrification adoption specific to the City’s ecosystem and its clean energy goals. The study aims to determine SVP’s incremental resource needs by comparing SVP’s load and resource forecast against key Integrated Resource Plan constraints (including resource adequacy requirements, Clean Energy and Climate Act targets); identify gaps for meeting the constraints; identify cost‐saving opportunities under existing arrangements; and propose resource solutions. The plan should develop a strategy to connect resource planning and beneficial electrification to form a cohesive decarbonization strategy.

Low Carbon Fuel Standard
In October of 2016, SVP entered a voluntary CARB program called the Low Carbon Fuel Standard (LCFS) Program. The LCFS Program was created through AB 32, California Global Warming Solutions Act of 2006 and Governor’s Executive Order S‐01‐07. The LCFS Program is a key part of a comprehensive set of programsin California to cut GHG emissions and othersmog‐forming and toxic air pollutants by improving vehicle technology, reducing fuel consumption, and increasing transportation mobility options. The LCFS Program is designed to decrease the carbon intensity of California’s transportation fuel pool and provide an increasing range of low‐carbon and renewable‐powered alternatives. The goal of this program is to reduce by at least 20% the carbon intensity of California’s transportation fuels by 2030.

Through compliance with the LCFS Program, SVP receives LCFS credits. These credits are sold in an exchange and these funds are to be used to comply with Title 17 of the California Code of Regulations Section 95483I (1) (A‐D), LCFS program proceeds may only be used in accordance with the following requirements.

Regulated Parties for Electricity
For electricity used as a transportation fuel, the party who is eligible to generate credits is determined as specified below:

For on‐road transportation fuel supplied through EV charging in a single‐ or multi‐family residence, the Electrical Distribution Utility is eligible to generate credits in its service territory. To receive such credits, the Electrical Distribution Utility SVP must:
 Use all credit proceeds to benefit current or future EV customers;  Educate the public on the benefits of EV transportation (including environmental benefits and costs of EV charging, or total cost of ownership, as compared to gasoline); Customer Programs, Energy Efficiency and Demand Response Resources2023 Integrated Resource Plan2023 Integrated Resource Plan
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 Provide rate options that encourage off‐peak charging and minimize adverse impacts to the electrical grid; and
 Include in annual compliance reporting the following supplemental information: an itemized summary of efforts to meet requirements (A) through (C) above and costs associated with meeting the requirements.

The LCFS combined with other programs, enables SVP to create an EV program that includes the following initiating activities in fiscal year 2021/22. SVP used LCFS proceeds to fund a residential electric bicycle rebate program where customers could receive a 10% rebate on the purchase price of a new e‐bike, up to $300. Income‐qualified customers were eligible to receive an additional rebate up to $200. SVP also funded an EV charging station rebate program to residents (up to $550), multi‐family properties (up to $3,000), schools and non‐profits (up to $5,000). We also offered an additional grant of up to $1,000 for the purchase and installation of qualified Level 2 EV Charging Stations to income‐qualified multi‐family properties. Beginning January 1, 2023, SVP increased the rebate amounts for the multifamily and commercial EV charging station rebate program that provided increased per port incentives(up to $8,000) for projects that installed 8+ charging connections. SVP’s rebate program offers up to $150,000 per site for Multifamily Residential Properties and Commercial Properties to help lower the upfront costs of Level 1 and Level 2 EV charging station projects. Increased incentives are available for projects that meet equity eligibility criteria.

In addition to offering rebates on the EV chargers, SVP also funded a income‐qualified EV rebate up to $1,500 to qualifying customers who purchased a new or used EV or plug‐in hybrid vehicle. In July 2023, this program transitioned to an income‐qualified rebate up to $3,500 for the purchase of a pre‐owned EV or plug‐in hybrid vehicle. Income qualified customers can receive $1,500 for a fully electric vehicle or $1,000 for a plug‐in hybrid vehicle. Customers who meet the Low‐Income Home Energy Assistance Program eligibility requirements may be eligible for a bonus rebate of $1,000. Vehicles with a miles per gallon gasoline equivalent of 117 or greater may be eligible for a bonus rebate of $1,000.

LCFS proceeds were also used to fund the Electric Vehicle Charging Access Project that furnished and installed Santa Clara‐owned Level 2 EV chargers at 16 public locations, libraries, parks, and community centers, near multi‐family properties and 6 city locations to jumpstart the implementation of the city’s Fleet Electrification Plan. LCFS funds were also spent to fund the California Clean Fuel Reward and the Peninsula‐Silicon Valley California Electric Vehicle Infrastructure Project 1.0 program. In 2021 and 2022, as a medium‐sized POUs, SVP wasrequired to transfer fundsto the CFR Program equal to 20% of proceeds generated from base credits from the LCFS program. Beginning 2023, the CFR requirement increased to 25%. The Peninsula‐Silicon Valley Incentive Project is no longer accepting applications as of June 2023.

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6. SVP System Modeling Approach

6.1. PLEXOS LT Overview
E3 performed resource portfolio optimization in this study using PLEXOS LT, an electricity system capacity expansion model that identifies the least‐cost long‐term combination of generation investments subject to reliability, policy, and operational constraints.21 PLEXOS LT considers investment costs, fixed costs, and production costs to simultaneously optimize long‐term capacity expansion and dispatch decisions. This allows the model to directly capture dynamic trade‐offs between investments and dispatch, such as energy storage investments versus renewable curtailment and/or overbuild. PLEXOS LT also captures the reliability contributions of all resources to the system towards satisfying its reliability constraint.

Figure 26 provides an overview of the PLEXOS LT model including the objective function, key model decisions, and key constraints.

Figure 26. Overview of the PLEXOS LT Model

6.2. Objective Function
The objective function minimizes the net present value (NPV) of electricity system forward looking costs over the planning horizon subject to constraints. Forward‐looking costs include investment costs, fixed costs, and production costs. Investment costs include the capital costs of new generation and storage resources. Fixed costs include fixed operations and maintenance (FO&M) costs of existing and new resources. Finally, production costs include variable operation and maintenance (VO&M) costs of existing 21 PLEXOS is a widely‐used commercially available software package from Energy Exemplar for electricity system modeling.

PLEXOS LT is the Long‐term plan phase of PLEXOS used for capacity expansion modeling.

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and new resources, fuel costs, and the costs of imported power (offset by any exported power revenues).

Figure 27 depicts an example optimal portfolio for a capacity expansion problem’s objective function.

Figure 27. Objective Function of Capacity Expansion Problem The objective function is also subject to investment and operational constraints (see next section).

Investment constraints include maximum resource potential for addition/retirement candidates (max/min units built/retired), and other potential policy‐related constraints,such as minimum RPS and SB 100 procurement requirements, emissions reductions requirements, and minimum reliability requirements. Operationally, the model is constrained by the hourly energy balance in each modeled period, resource limits set by energy, fuel, emissions, and other limits of generation and storage.

6.3. SVP System Representation
In E3’s modeling approach, SVP’s system is represented with a simplified zonal topology consisting of two nodes (“SVP” and “External”) and a single transmission connection. The SVP node contains SVP’s load and local existing and planned resources (DVR, Cogen, Gianera, and the planned BESS project). The External node contains SVP’s other existing and planned resources, candidate expansion resources, and the CAISO market, with which SVP can buy and sell electricity. Figure 28 illustrates SVP’s simplified topology used in the capacity expansion model.

Figure 28. Simplified Topology for Capacity Expansion Model SVP System Modeling Approach2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   62
In addition to their contracted resources, SVP can execute market transactions with other CAISO entities for energy, RECs, and RA attributes. For the IRP, only the energy market interactions are modeled. In every hour of the modeling horizon, SVP has the option to either purchase electricity from the market to serve load or to sell generation from its owned/contracted portfolio to the market. These interactions include both the cost/value of imports/exports as well as the associated carbon emissions. In the SVP system topology (Figure 28), the CAISO Market is in the External Node, and any purchases must flow over the transmission line to serve SVP’s load.

The hourly market price forecast used to Inform SVP’s market decisionsis derived from E3’s CAISO Market Price Forecast dataset.22 Annual averages of the hourly price forecast are provided in Figure 29. Average market prices over the 2025‐2035 horizon are primarily influenced by near‐term solar build‐out and transmission flow constraints between Northern and Southern California. The hourly market prices are correlated to the market emissions rate, discussed in Section 6.4. E3’s price forecasts represent a fundamentals‐based view of the CAISO market, including long‐run portfolio changes to meet the energy, reliability, and policy requirements of the region.

Figure 29. CAISO Market Average Annual Price Forecast, $/MWh Price forecasts used in capacity expansion modeling are typically an hourly‐varying input price stream that does not change with system dynamics. While these price streams are useful to approximate the complicated dynamics that occur outside the area of interest, they can, in many instances, overstate the arbitrage opportunities that may exist between external resources and resources within the area of interest (i.e., SVP’s territory). To the extent that unrealistic arbitrage opportunities exist for these transactions, the result may be a portfolio that is too reliant on external transactions relative to what will be realized in practice. It is therefore prudent for modeling and planning to restrict market transactions 22 Purchase required. https://shop.ethree.com/product/caiso‐price‐forecast‐2022‐edition‐core‐case/.

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in capacity expansion simulations to minimize the impact that these transactions may have on the resource portfolio.

To limitspeculation on external market revenuesfrom biasing SVP’s portfolio economics, for IRP modeling in PLEXOS,salesto the CAISO Market are capped at 20% of SVP’sload in each hour, and 5% of SVP’s annual load in each year. These values were determined based on SVP’s historical market activity and risk tolerance to market exposure. These constraints prevent the over‐procurement of resources for energy trading and limit any model behavior associated with a potential disequilibrium between the market price forecast and the SVP IRP inputs. These constraints only impact market interactions and do not limit the availability of SVP‐contracted resources in the External node (Section 4, Section 7) to utilize SVP’s dedicated transmission lines.

In Scenario 3: Zero Emissions with Emerging Technology (Zero Emissions Scenario), market activity is restricted to obey the zero hourly emissions rule, whereby emissions are only allowed during hours with 0 MT CO2/MWh emissionsfactors(i.e., when excessrenewable energy in the CAISO would have otherwise been curtailed). This is discussed in detail in Section 6.4.

6.4. Model Constraints
Resource Adequacy Modeling Approach
Traditionally, for near term local resource adequacy the CEC published a monthly Coincident Peak for all CAISO load serving entities (LSEs), including SVP, based on their respective load forecastsfor the following year. Per CAISO Tarif Section 40 From the coincident peak number the CEC and CAISO required LSEs to provide sufficient capacity to meet each LSE’s needs (115% of the coincident peak), through Local and System requirements for the upcoming year. The Local Requirement is the amount of capacity required to be satisfied by local resources classified as being able to meet that LSE’s local Requirement, and the remaining amount can be satisfied by system resources not tied to a specific location.23 However, the long‐term RA requirements and future input data for SVP (PRM,resource accreditation, etc.) are uncertain as the California Public Utilities Commission (CPUC) moves towards the “slice‐of‐day” approach for resource adequacy.24 Once slice‐of‐day is implemented, CPUC jurisdictional LSE resource accreditation will be done within a spreadsheet model using LSE specific loads; no resource level accreditation metrics(like the average ELCCs published for solar and wind historically) will be available for POUs to utilize. Even if the historical approach were to be maintained, there are no public CAISO system level forecasts of average ELCCs for solar, wind, and storage, which form the bulk of forecasted SVP capacity additions. For these reasons, SVP has opted to follow the long‐term planning method for system reliability needs consistent with the CPUC‘s approach for itsjurisdictional LSEs utilized in the current 2022‐ 23 SVP Local Area Requirements can be satisfied by resources within the local areas of Humbolt, North Coast/North Bay, Stockton, Greater Bay, Greater Fresno, Kern, Bid Creek/Ventura, LA Basin, San Diego/Imperial Valley 24 CPUC, “Resource Adequacy Homepage,” California Public Utilities Commission, 2023, https://www.cpuc.ca.gov/industries‐ and‐topics/electrical‐energy/electric‐power‐procurement/resource‐adequacy‐homepage.

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2023 CPUC IRP cycle. This approach, as described in the following section, plans for the “marginal reliability need” using marginal effective load carrying capability (ELCC) accreditation for all resource types.

Local reliability needs are not explicitly optimized in SVP’s IRP, as SVP’s procurement approach for their slice of the PG&E transmission territory local resource needs is to primarily rely on short‐term market purchases and sales to balance their local reliability position. SVP’s plan also relies on significant growth of remote solar, wind, storage, and geothermal resources; some of these could be sited in locally constrained areas. SVP will rely on resource adequacy market purchases to fill any residual local reliability needs.

System Reliability Constraints
Meeting reliability needs is a critical component of utility integrated resource planning. Amongst utilities, SVP – and other CAISO LSEs – face a unique reliability planning situation, whereby 1) system reliability needs are measured at the CAISO level, 2) LSEs have their own bilateral RA obligations, and 3) the long‐ term system reliability value of LSE resources is dependent upon the resource decisions of all LSEs. Using inputs developed by the CPUC for use in CPUC jurisdictional LSE IRPs, the reliability constraints in PLEXOS are set up to reflect this unique situation.

For their 2022 IRPs, the CPUC directed LSEs to plan for their share of the “marginal reliability need” using marginal ELCC accreditation for all resource types. This represents a departure from the historical paradigm in the CPUC RA process to rely on “average” ELCCs, but provides a more accurate – and therefore economically efficient – long‐term forecast of the marginal system reliability value of incremental resource changes on top of the larger CAISO fleet. It therefore represents a robust set of reliability planning inputs for SVP’s IRP process, consistent with the latest long‐term planning guidance available from a California state agency.

Figure 30 illustrates the key steps for a marginal reliability planning process: 1) determining the periods of future loss of load risk under a forecasted system‐level portfolio, 2) calculating and allocating the marginal reliability need during those same periods, and 3) measuring the resource contributions during those risk periods using marginal ELCC.25
25 Note: The marginal reliability need can be calculated in two ways to arrive at the same value: 1) as shown in this diagram, it can be calculated as the gross load plus operating reserves minus allowed loss of load under the adopted reliability standard, or 2) as the sum of the marginal ELCCs of the resource portfolio that is tuned to the adopted reliability standard.

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Figure 30. Schematic of the Marginal Reliability Planning Process The following process was used by the CPUC to develop their marginal reliability planning inputs, used for the IRPs of the CPUC jurisdictional LSEs as well as for SVP’s IRP:

1. Data Development: A loss of load probability model and dataset were developed. The CPUC uses Astrapé’s SERVM model for this purpose, considering weather, load, and renewable variability over 23 historical years of weather conditions (1998‐2020) as well as stochastic draws for forced outages and economic load uncertainty.

2. System‐level Need Determination: Using the loss of load probability model, the Total Reliability Need was be calculated by measuring the total effective capacity (i.e., ELCC MW or perfect capacity (PCAP) equivalent MW) needed to reach the CPUC’s 1‐day‐in‐10‐years loss of load expectation (LOLE) standard (also described as reaching 0.1 days/year LOLE).

3. CAISO level resource portfolio forecast: a forecasted resource portfolio for the entire CAISO was developed based on the CPUC’s 2021 Preferred System Plan, tuning that resource portfolio to the

0.1 days/year LOLE standard each year.

4. Marginal ELCC forecast: the marginal ELCC for each resource type in the forecasted portfolio was calculated for key years (with between years using interpolation) to produce an annual forecast of marginal ELCCs by resource type. Marginal ELCCs are calculated as removing a small increment (e.g., 100 MW) of each resource type from the portfolio and calculating the perfect capacity equivalent, measuring the marginal value of each resource type to reduce loss of load risk.

5. Translation of the total need into the marginal reliability need for use in LSE IRPs: when accrediting against the total ELCC required to reach 0.1 LOLE in all hours, “average ELCCs” are used. For a system at the reliability criteria, the sum of average ELCCs for all resources equals the Total Reliability Need MW to reach the reliability criteria. However, when accrediting using SVP System Modeling Approach2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   66
marginal ELCCs, which produce a more economically efficient signal of the marginal reliability value of each resource, the sum of the marginal ELCCs produces a lower MW value than the Total Reliability Need. Thislower MW value isthe marginalreliability need. For a system at the reliability criteria, the sum of marginal ELCCs for all resources equals the marginal reliability need MW to reach the reliability criteria. The CAISO’s marginal reliability need was calculated by the CPUC for each year based on the sum of the marginal ELCCs for the resource portfolio tuned to the reliability criteria.

6. Allocation of the marginal reliability need to each LSE: the CPUC allocates the system level marginal reliability need to each LSE based on their share of the IEPR’s coincident managed peak.

While this does not fully capture LSE contributions during the multiple hours where loss of load risk may occur, it used existing available data and – due to the large behind the meter PV peak shift captured in the managed peak – is a reasonable initial proxy for LSE contributions during the net peak.26
The resulting marginal ELCCs by resource and the marginal reliability need published by the CPUC for use by their jurisdictional LSEs are shown in Figure 31. These values come from the “38 MMT by 2030” modeling scenario from the 2021 Preferred System Plan.27 26 Gross peak = the consumption peak prior to behind the meter (PV, storage, etc.) resource output. Managed peak = the metered peak after behind the meter resource output. Net peak = the resulting system load after the output from supply side renewable resources. The net peak can also be defined as the remaining system load after all variable and use limited resources are dispatched (including storage, hydro, DR, etc. and not just solar and wind), which would align it more critically with the hours of loss of load risk for a system with increasing battery storage penetrations. 27 Slide 42, “Reliability Filing Requirements for Load Serving Entities’ 2022 Integrated Resource Plans – Results of PRM and ELCC Studies.” https://www.cpuc.ca.gov/‐/media/cpuc‐website/divisions/energy‐division/documents/integrated‐resource‐plan‐ and‐long‐term‐procurement‐plan‐irp‐ltpp/2022‐irp‐cycle‐events‐and‐materials/20220729‐updated‐fr‐and‐reliability‐mag‐ slides.pdf.

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Figure 31. Marginal ELCCs by Resource Type from the CPUC 38MMT Scenario The inputs used for the CPUC IRP process were also utilized as the key inputs for the reliability constraint in the SVP IRP. SVP’s marginal reliability need was calculated using its forecasted share of the CAISO coincident managed peak in the 2022 IEPR. The SVP managed peak MW was divided by the CAISO managed peak MW; this ratio was then multiplied by the CPUC’s marginal reliability need to obtain the SVP‐level need. This marginal reliability need represents SVP’sshare of the system need during hours with loss of load risk as measured in ELCC MW. All existing and new candidate resource options in PLEXOS’s optimization that provide system RA attributes are also counted in ELCC MW, using the marginal ELCC percentages reported above. This approach puts all resources on a level playing field by measuring their reliability contributions consistently using marginal ELCC, which accounts for the operational limitations of all resource types, including variable renewables, use‐limited hydro, use‐limited energy storage, and thermal units subject to forced outages.

Figure 32 showsthe contributions of SVP’s existing and planned resourcestowardsitsforecasted marginal reliability need. The shortfall between the existing portfolio ELCC MW and SVP’s marginal reliability need must be satisfied via candidate resource builds. Due to constraints on candidate resource availability (see Section 7.1), the reliability constraint will not be enforced until 2026.

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Figure 32. Existing and Planned Resource Marginal ELCC and SVP’s Reliability Need, 2026‐3528 Clean Energy and Emissions Reduction Requirements
SVP must satisfy three key policy criteria in its IRP. SB 100 and SB1020 set targets for the RPS and Clean Energy Standard (CES) annually through 2045, and the CARB has also stipulated a GHG reduction target for 2030.
 RPS targets stipulated in legislation are 44% of retail electricity sales by 2024, 52% by 2027, and 60% by 2030.29 Only eligible renewable energy resources qualify for the RPS, including solar, wind, geothermal, and small hydroelectric units.
 CES policy goals are 90% by 2035, 95% by 2040, and 100% by 2045. Resource qualification for the CES is expanded to include allzero‐carbon resources, including nuclear, large hydro, and emerging 28 The marginal reliability constraint is only enforced in the model beginning in 2026, which is the first year when SVP expects to be able to sign new long‐term contracts as discussed in Section 7. In the intervening years, it is assumed that SVP will sign short‐term capacity contracts to meet their reliability need if there is any capacity shortage. 29 The RPS constraint is only enforced in the model beginning in 2026, which is the first year when SVP expects to be able to sign new long‐term contracts as discussed in Section 7. In the intervening years, it is assumed that SVP will buy RECs if there is any REC shortage.

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technologies such as hydrogen and Carbon Capture and Storage (CCS). In the intervening years between the expiration of the RPS (2030) and the enforcement of the CES (2035), a ramp‐up is modeled to smooth policy compliance in the model (Figure 33).  GHG reductions target the electric sector’s share of a 40% economy‐wide reduction of GHG emissions from 1990 levels by 2030. For SVP, this amounts to 485,000 MMT CO2e, as published in the SB 350 Final Report.30 This value represents the high end of the GHG target range published by CARB and hence the minimum requirement for SVP. Scenarios of more aggressive carbon reduction were modeled focused on the year 2035, as described below.

The schematic outlined in Figure 33 shows the compliance targets for the RPS and CES, expressed as percentages of retail sales.

Figure 33. RPS (Green) and CES (Blue) Compliance Targets All of SVP’s existing and planned renewable resources, including solar, wind, geothermal, biogas, and small hydro generators, are assumed to be REC‐producing and qualify towards RPS compliance. Additionally, all candidate wind, solar, and geothermal resources selected in the capacity expansion model are assumed to provide RECs to SVP.

In addition to renewable resources, SVP’s portfolio of large hydro generators is assumed to qualify for the CES and provide credits to SVP. Candidate renewables and zero‐emission emerging technologies are assumed to qualify for the CES as well.

The GHG constraint is enforced starting in 2030. Gas‐fired thermal generators are assumed to generate carbon emissions at a rate of 117 pounds CO2 per MMBtu of fuel consumption. When LEC undergoes its planned conversion to 45% hydrogen fuel blending in 2027, its emissions factor reduces to 92.2 pounds per MMBtu of blended fuel (see Emerging Technology in Section 7.1). The Allam Cycle CCS resource modeled in Scenario 3: Zero Emissions with Emerging Technology (Zero Emissions Scenario) has a 100% 30 CARB, “Senate Bill 350 ‐ Integrated Resource Planning Electricity Sector Greenhouse Gas Planning Targets: 2020 Update” (Sacramento, CA: California Air Resource Board (CARB), 2020), https://ww2.arb.ca.gov/sites/default/files/2021‐04/sb350‐ final‐report‐2020.pdf.

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carbon capture efficiency, and consequently is not modeled as producing emissions. When Gianera 1 and 2 convert to renewable natural gas (RNG) in the Zero Emissions Scenario, the lifecycle carbon emissions of RNG are assumed to be zero. For more information on the emerging technologies under consideration, refer to Section 7.1.

Market interactions also contribute to the carbon emissions constraint. The hourly market emissions factors used for purchases and sales are equal to the average hourly emission factors from the CAISO‐ wide thermal generator fleet that dispatches in each hour, as calculated from the E3 CAISO Market Price forecast dataset.31 Purchases in each hour from the market incur a carbon penalty at the hourly market emissions factor, while market sales offset SVP’s carbon emissions at that same rate. This representation is consistent with the emissions accounting approach used in the CPUC IRP and reflects SVP’s continuous participation in the CAISO market.

A volumetric cost is modeled for every ton of carbon produced by SVP. These costs are also taken from the E3 CAISO Market Price Forecast. Market prices, emission factors, and carbon prices are all correlated in this dataset.

The CAISO average annual emission factors and annual carbon price forecasts are shown in Figure 34.

Figure 34. CAISO Average Annual Emissions Factor and Carbon Price In the Zero Emissions Scenario, the GHG constraint is modified such that no emissions are permitted in all hours of the year, beginning in 2035. Under this scenario, market sales do not offset SVP emissions, and 31 E3, “California ISO Market Price Forecast E3 Core Case 2022,” Energy + Environmental Economics (E3), 2022, https://shop.ethree.com/wp‐content/uploads/2022/11/Market‐Summary_CAISO_2022‐edition_SAMPLE.pdf.

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market purchases are only allowed in hours where the average market emissions factor is zero. For more information, refer to Section 6.6.

6.5. Capacity Expansion Model Configuration
To identify a least‐cost capacity expansion and system operations portfolio, PLEXOS LT optimizes across the entire planning horizon from 2024 to 2035 (11 years) in a single step, resulting in a computationally intensive optimization problem. To ensure the capacity expansion problem is computationally tractable while still providing accurate and actionable results, PLEXOS performs several modifications to the system’s representation to make the model more tractable. These modifications are described in the following sections.

Day Sampling
Regarding the chronology or level of detail in representing the planning horizon, day sampling ensures that the model captures intra‐month and monthly variations in load and resources annually while reducing the size of the simulation. Instead of modeling every day of the modeling horizon, a sample set of three days per month are studied. A statistical sampling algorithm within PLEXOS LT extracts similar periods (such as days, weeks, months) with a focus on highly variable data (such as load, solar and wind profiles), leaving a sample set of days that, together, have characteristics that are representative of conditions on the electricity system over the course of multiple years. After sampling, PLEXOS LT rescales the results to ensure that the total energy equals the original input values.

Expansion Decisions
The capacity expansion algorithm in PLEXOS LT can be programmed to select new generator builds using integer decision variables or linearized variables. In the integer representation, each generator must be built at its full nameplate capacity, or not at all. In the linear representation, partial builds are allowed. In general, integer/discrete problems are much harder for PLEXOS to solve than linear problems. In thisstudy, the model is permitted to make linear expansion decisions, which significantly reduces the computational time required to solve the problem while still providing sufficient information on the magnitude and diversity of new builds to support decision making.

Operation Decisions
Operations unit commitment optimality determines how unit commitment decision variables are treated in the optimization problem. Operationsin PLEXOS LT are simulated through economic dispatch of existing and new resources to meet load in each hour. The dispatch logic depends on the type of resource. Solar and wind resources have fixed generation profiles(input as hourly capacity factors) based on the resource location and can be curtailed when total generation exceeds load. Thermal resources (such as natural gas turbines) are operated flexibly while meeting operating constraints such as maximum capacity rating and minimum generation level. Must‐run resources are operated at their rated capacity in all hours except for planned outages. Market purchases and demand response resources are configured similarly to SVP System Modeling Approach2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   72
generation and can be operated flexibly while also meeting operating constraints. Energy storage resources (such as batteries and pumped hydropower) increase load when charging and can serve load when discharging.

6.6. Scenarios and Sensitivities Considered
Three modeling scenarios and one modeling sensitivity were considered for the SVP IRP. Scenario 1: Base SB 100 (Base Scenario) consists of the default inputs and assumptions regarding load growth, resource availability, policy targets, and market activity. Under Scenario 2: Accelerated SB 100 (Accelerated SB 100 Scenario), the compliance targets are accelerated from 60% RPS to 70% carbon‐free energy (60 % still needs to come from renewable resources) by 2030, and from 90% carbon‐free energy to 100% by 2035.

Finally, Scenario 3: Zero Emissions with Emerging Technology (Zero Emissions Scenario) restricts SVP from producing any carbon emissionsin all hoursstarting in 2035, enablesthe selection of certain zero‐emitting emerging technologies beginning in 2035, and includes conversion of LEC, DVR, and Gianera 1 and 2 to zero‐carbon fuels by 2035. The emissions restrictions in this Scenario extend to market activity, where purchases are only allowed during hours where the market average emissions rate is zero, and sales are not permitted to provide negative emissions “credits” during hours when market average emissions rates are non‐zero.

The Geothermal Limitations and Hydrogen Challenges Sensitivity (Hydrogen Sensitivity) represents a variation of the Zero Emissions Scenario where the geothermal resource potential available to SVP is capped to 50 MW and the costs of hydrogen retrofits, new hydrogen turbines, and hydrogen fuel are increased due to uncertainty over a future hydrogen economy.

A summary of the key changes by Scenario are shown in Figure 35 below.

Figure 35. Modeling Parameters that Vary by Scenario or Sensitivity Scenario 1: Scenario 2: Scenario 3: Sensitivity:

Parameter Base SB 100 Accelerated SB
100
Zero Emissions
with Emerging
Technology
Geothermal
Limitations and
Hydrogen
Challenges
SB 100 CES
Targets
90% by 2035
100% by 2045
70% by 2030
100% by 2035
70% by 2030
100% by 2035
70% by 2030
100% by 2035
Carbon Emission
Reduction Targets
485,000 MT by
2030
485,000 MT by
2030
485,000 MT by
2030
Zero hourly
emissions
beginning in 2035
485,000 MT by
2030
Zero hourly
emissions
beginning in 2035
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Zero‐carbon
Emerging
Technologies
Not included Not included Included Included
Gas Plant
Conversions*
LEC 45%
(volumetric)
Hydrogen in 2027
LEC 45%
(volumetric)
Hydrogen in 2027
All gas plants are
converted to
100% zero‐carbon
fuels by 2035
All gas plants are
converted to
100% zero‐carbon
fuels by 2035
Market Purchases Allowed Allowed
Allowed before
2035
Restricted in 2035
to hours where
market emission
factor is zero
Allowed before
2035
Restricted in 2035
to hours where
market emission
factor is zero
Carbon Credits
via Market Sales Allowed Allowed
Allowed before
2035
Not allowed in
2035
Allowed before
2035
Not allowed in
2035
Geothermal
Resource
Potential
Default Default Default Reduced to 50
MW in 2028
Hydrogen
Retrofit, New
Build, and Fuel
Costs
Default Default Default High
*Gas plant conversions are discussed in Section 7.1.

6.7. Model Inputs
The inputs to the PLEXOS model, discussed in Sections 3, 4, 6, and 7, are organized into the following topics:
 Load Forecast – The load forecast was developed using a combination of a baseline load forecast provided by SVP and load modifiers to form a Reference Scenario forecast. This load forecast was used in all scenarios. See Section 3.
 Existing and Planned Resources – Inputs were provided by SVP and are discussed in Section 4:

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o Online and retirement dates – As a PLEXOS modeling assumption, all of SVP’s small and large hydro generators are retained over the planning horizon, irrespective of contract status.
o Nameplate capacity
o Variable O&M
o Thermal operating parameters
o Generation profiles & capacity factors – Geothermal and hydro energy budgets were provided by SVP. Renewable solar and wind profiles were collected from the CPUC IRP 2023 Inputs and Assumptions (I&A) supporting information.  Candidate Resources – Inputs were developed by E3 and are discussed in Section 7:
o Resource costs – Resource costs for candidate resources were derived from the National Renewable Energy Laboratory (NREL) 2023 Annual Technology Baseline (ATB).32 Emerging technology cost assumptions were collected via E3 literature review. o Resource Potential & Availability – The availability and build limits for candidate resources were collected from the CPUC IRP 2023 I&A document, with modifications to reflect SVP’s market share and procurement risk.33
o Generation Profiles & Capacity Factors – Profiles were collected from the CPUC IRP 2023 I&A supporting information.
o Thermal Operating Parameters – Data was taken from the CPUC IRP 2023 Resource Cost and Build workbook.
 Reliability Need – Inputs were developed by E3 and are discussed in Section 6.4:
o Reliability Need – Developed using the CPUC data and SVP’s coincident peak demand to derive the SVP marginal reliability need.
o Resource Capacity Contributions – The marginal ELCCs for candidate renewable resources were adopted from CPUC data, using a marginal reliability need framework.  Fuel Prices – These trajectories were derived from several data sources. More information can be found in Section 7.4, including:
32 https://atb.nrel.gov/electricity/2023/index 33 Resource potential and availability limits were reduced from the CAISO‐wide potentials to represent what would be available to SVP for procurement. Further discussion can be found in Section 7.1.

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o Natural Gas – The gas forecast was derived from the Energy Information Administration 2022 Annual Energy Outlook, with the trajectory regionalized to the settlement node of SVP’s contracted gas supply.
o Hydrogen – Green hydrogen price forecasts were developed by E3. The forecast assumes electrolysis of hydrogen using an alkaline electrolyzer that is powered by solar energy.

Hydrogen electrolyzer costs are derived from the CEC publication on hydrogen production costs.34 Hydrogen storage costs are derived from Department of Energy (DOE) project ST‐ 001 costs.35 Hydrogen transport costs are derived using Argonne’s Hydrogen Delivery Scenario Analysis Model (HDSAM).36 A $3/kg Production Tax Credit (PTC) from the IRA is applied to units brought online by 2035.37
o Renewable Natural Gas – Fuel cost provided by SVP.
o Uranium – Fuel cost taken from the CPUC IRP 2023 Resource Cost and Build Workbook.

6.8. Model Outputs
The following outputs are produced by PLEXOS and are the subject of discussion and interpretation in this report. All fields are reported annually for each generator, except for the Constraint outputs which are single‐defined values for each year of the modeling horizon. The key model outputs for this IRP are reported in Figure 36.

Figure 36. Key Model Outputs
PLEXOS Output Description Output Units
Installed Capacity Installed capacity of Generation and Battery Storage. MW Generation Total annual generation of Generation and Battery Storage. GWh Annualized Build Cost Total fixed costs of candidate resources, including levelized capital costs and FO&M costs.

Nominal $’000
VO&M Cost Total VO&M cost. Nominal $’000
Fuel Cost Total annual fuel bill. Nominal $’000
Market Net Purchases Energy purchases from the market, net of sales to market. GWh Market Cost Cost of market purchases. Nominal $’000
Market Revenue Revenue (negative cost) collected from market sales. Nominal $’000 Emission Production Total production of carbon emissions, including from generation and market activity.

Short tons
Emission Cost Total cost of emissions, equal to the emission price times production.

Nominal $’000
34 https://www.energy.ca.gov/sites/default/files/2021‐06/CEC‐500‐2019‐055‐F.pdf.   35 https://www.hydrogen.energy.gov/pdfs/review22/st001_ahluwalia_2022_p.pdf.   36 https://hdsam.es.anl.gov/index.php?content=hdsam.   37 Qualification of hydrogen generators for the Hydrogen PTC under the IRA assumes a three‐year safe harboring following the expiration of the IRA tax credits in 2032. The PTC applies to the first ten years of plant operations. This credit is levelized over the useful life of the hydrogen generator and is bundled into the fuel price forecast.

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7.Portfolio Expansion Resource Options

7.1. Candidate Resource Assumptions
When planning for capacity expansion, SVP can select from a range of candidate resource optionsto meet growing load, reliability requirements, GHG policy targets, and additional policy goals. These resources are grouped into the following categories:
 Candidate Renewable Resources
 Candidate Storage Resources
 Candidate Thermal Resources
 Candidate Emerging Technology Resources
For resource cost assumptions, see to Section 7.2.

Candidate Renewable Resources
Candidate renewable resources include the renewable energy resources available to SVP under all modeling scenarios. These are established and commercially viable technologies, including solar PV, in‐ state wind, out‐of‐state wind, offshore wind, and geothermal.

The candidate renewable resources available to SVP are aggregations of the resources reported in the CPUC IRP I&A document.
38 For solar and in‐state wind, the resource potentials were aggregated into Northern, Central, and Southern regions according to the region boundaries used by the CPUC.

Geothermal is represented as a single resource encompassing all in‐state geothermal resource potential in the CPUC model. Details of the aggregation are summarized in Figure 37.

Figure 37. SVP Candidate Renewable Resources Mapping to CPUC Aggregation SVP Resource Name CPUC Aggregation
Northern California Solar Northern California
Central California Solar Southern PGAE, Greater Kramer, Tehachapi, Southern NV Eldorado Southern California Solar Greater LA, Riverside, Greater Imperial, Arizona Northern California Wind Northern California, Solano
Central California Wind Central Valley North Los Banos, Tehachapi, Southern NV Eldorado Baja California Wind Baja California
Geothermal All in‐state geothermal resources
The resource potentials available to SVP are indexed to the corresponding potentials from the CPUC IRP I&A document. Specifically, the solar resource potential is assumed to be sufficiently large to capture all of SVP’s potential needs, and no resource potential limit is modeled. For in‐state wind, out‐of‐state wind, 38 CPUC 2022‐23 IRP Cycle Events and Materials. https://www.cpuc.ca.gov/industries‐and‐topics/electrical‐energy/electric‐ power‐procurement/long‐term‐procurement‐planning/2022‐irp‐cycle‐events‐and‐materials.

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and offshore wind, the portion of the CPUC resource potentials available to SVP is assumed to be 5% of the reported totals, reflecting SVP’s market share and ability to procure wind generation. For Baja California Wind, the available potential reported by the CPUC is also reduced to account for Cimarron Wind, for which SVP is already under contract. For geothermal, it is understood that, of the 3.3 GW of resource potential modeled in the CPUC IRP, 1 GW of this resource must be earmarked for the CPUC Mid‐ Term Reliability Clean Firm order. As such, SVP’s portion of the CPUC resource potential for geothermal is represented as 15% of the net remaining statewide potential of 2.3 GW.

Each candidate renewable resource’s first available year reflects feasible timelines for bringing resources online based on the CAISO interconnection queue and typical development lead times. Additionally, no resources are made available for selection in the capacity expansion model until 2026 at the earliest, reflecting SVP’s near‐term procurement decisions.

For candidate solar and wind resources, the renewable profiles and capacity factors were adopted from the profiles used in the CPUC IRP model.39 A single weather year(2020) wassampled to create the profiles.

Weather stations were selected for candidate renewable resources that align with the geographic extent of the resource potential.

Key metrics for the candidate renewable resources available to SVP are summarized in Figure 38. The resource potential totals represent the total amounts available to the model by 2035; for wind and geothermalresources, the available potential isstaggered between 2026‐2030 to reflect construction lead time, projects in the CAISO interconnection queue, and commercial interest.

Figure 38. Candidate Renewable Resource Options
Technology Resource Name First Year
Available
Resource
Potential
Lifetime
(years)
Capacity
Factor
Solar Northern California Solar 2026 Uncapped 30 29.9%
Solar Central California Solar 2026 Uncapped 30 32.5%
Solar Southern California Solar 2026 Uncapped 30 33.7%
Solar Distributed Solar 2026 36.6 GW 30 25.9%
In‐State Wind Northern California Wind 2026 142 MW 30 21.2% In‐State Wind Central California Wind 2026 478 MW 30 33.2% In‐State Wind* Baja California Wind 2026 109 MW 30 30.4% Out‐of‐State Wind New Mexico Wind 2026 275 MW 30 48.1%
Out‐of‐State Wind Wyoming Wind 2027 200 MW 30 51.2%
Offshore Wind Humboldt Bay Offshore Wind 2034 134 MW 25 57.1% Offshore Wind Morro Bay Offshore Wind 2034 244 MW 25 47.6% Geothermal Geothermal 2028 347 MW 25 ‐
* Baja California Wind interconnects directly to the CAISO system and is considered in‐state 39 CPUC System Reliability Modeling Datasets 2023. https://www.cpuc.ca.gov/industries‐and‐topics/electrical‐energy/electric‐ power‐procurement/long‐term‐procurement‐planning/2022‐irp‐cycle‐events‐and‐materials/system‐reliability‐modeling‐ datasets‐2023.

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Further breakdowns of the average solar and wind capacity factors by month, as calculated from the CPUC weather profiles, are provided in Figure 39 and Figure 40.

Figure 39. Candidate Solar Monthly Capacity Factor
Month Central
California Solar
Northern
California Solar
Southern
California Solar
Distributed
Solar
January 20% 14% 24% 19%
February 29% 29% 29% 24%
March 28% 25% 31% 23%
April 36% 35% 40% 28%
May 44% 35% 43% 33%
June 44% 43% 44% 33%
July 45% 46% 40% 33%
August 38% 36% 38% 29%
September 33% 29% 35% 26%
October 27% 29% 31% 24%
November 24% 21% 26% 20%
December 21% 16% 23% 17%
Annual 32% 30% 34% 26%
“I think we should continue to explore the viability of other energy options, such as hydrogen or even
nuclear.” ‐Santa Clara resident survey response
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Figure 40. Candidate Wind Monthly Capacity Factor
Month Baja CA
Wind
Central CA
Wind
New
Mexico
Wind
Northern
CA Wind
Wyoming
Wind
Humboldt
Bay
Offshore
Wind
Morro Bay
Offshore
Wind
January 18% 37% 59% 22% 72% 56% 51%
February 19% 39% 56% 27% 63% 69% 48%
March 32% 31% 62% 27% 54% 44% 29%
April 38% 28% 60% 17% 47% 45% 61%
May 43% 39% 51% 24% 42% 60% 56%
June 47% 34% 46% 16% 40% 65% 51%
July 44% 29% 27% 14% 37% 83% 48%
August 34% 21% 23% 12% 33% 70% 49%
September 22% 24% 35% 21% 46% 37% 42%
October 29% 28% 47% 25% 54% 68% 34%
November 21% 39% 55% 23% 60% 43% 50%
December 19% 48% 56% 26% 68% 47% 52%
Annual 30% 33% 48% 21% 51% 57% 48%
Candidate Storage Resources
To complement candidate renewables, candidate energy storage resources are represented in SVP’s capacity expansion model. Energy storage resources can shift the generation from variable renewable resources to serve load during critical system hours when renewables might otherwise not be producing electricity. Four energy storage resources are modeled, including both conventional technologies (Li‐ion batteries, Pumped Hydro Storage) and a generic emerging energy storage technology. The four energy storage resources each have a different storage duration, allowing the model to select the optimal mix of storage capacity and duration.

Li‐ion batteries are modeled in two durations (4‐ and 8‐hr) and are available for selection immediately in 2026. Pumped Storage is modeled with a 12‐hr duration and is the only energy storage resource modeled with limits on the available resource potential. The resource potential for Pumped Storage is taken from the CPUC IRP I&A document.40 This resource is an aggregation of several project sites that have been identified as suitable for development, the first of which could be developed as early as 2027. Finally, the Generic Energy Storage (100‐hr) resource is only available for selection in scenarios where emerging technologies are allowed, starting in 2036.

Key metrics for the candidate storage resources available to SVP are summarized in Figure 41. 40 CPUC 2022‐23 IRP Cycle Events and Materials. https://www.cpuc.ca.gov/industries‐and‐topics/electrical‐energy/electric‐ power‐procurement/long‐term‐procurement‐planning/2022‐irp‐cycle‐events‐and‐materials.

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Figure 41. Candidate Storage Resource Options
Resource Name Duration
(hr)
First Available
Year
Cumulative
Build Limit
Lifetime
(years)
Round‐Trip
Efficiency
Li Battery 4hr 4 2026 Uncapped 20 85%
Li Battery 8hr 8 2026 Uncapped 20 85%
Pumped Storage 12hr 12 2027 3.2 GW 50 70%
Generic Energy Storage 100hr 100 2036 Uncapped 20 45%
Candidate Thermal Resources
Candidate thermal resources are also made available to SVP in scenarios where new emitting resources are allowed to be procured. These include new combined cycle gas turbines (CCGTs), CTs, and reciprocating engine units. The first available year for all new thermal units is 2027. New thermal units are assumed to be procured from outside the SVP system.

Key metrics for the candidate thermal resources available to SVP are summarized in Figure 42 and Figure

43. Figure 42. Candidate Thermal Resource Options
Resource Name First Available
Year
Cumulative Build
Limit2
Lifetime
(years)
Advanced CCGT 2027 Uncapped 25
Aero CT 2027 Uncapped 25
Reciprocating Engine 2027 Uncapped 25
Figure 43. Candidate Thermal Operating Parameters
Resource Name
Heat Rate Curve VO&M
($/MWh) Intercept Fuel Type
(MMBtu)
Slope
(MMBtu/MWh)
Advanced CCGT 500 6.0 2.12 Spot Gas
Aero CT 346 6.0 6.96 Spot Gas
Reciprocating Engine 4.9 9.2 6.96 Spot Gas
Emerging Technology Resources
Emerging technology resources include zero‐carbon technologies that have not yet reached full commercialization. These resources are not included in core portfolios that are considered for adoption in SVP’s IRP; they are only considered in Scenario 3: Zero Emissions with Emerging Technology (Zero Emissions Scenario) and the Geothermal Limitations and Hydrogen Challenges Sensitivity (Hydrogen Sensitivity). Emerging technologies under consideration include both candidate emerging technology resources, which are subject to optimization decisions in the PLEXOS capacity expansion model; and planned emerging technology conversions, which include retrofits and fuel conversions ofspecific thermal generators for the combustion of zero‐carbon fuels. While emerging technologies are generally more expensive to build and operate than conventional renewable resources, their chief advantage is that they are firm, non‐emitting resources capable of serving peak load.

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Candidate emerging technology resources under consideration in the IRP are Allam Cycle CCS with 100% carbon capture efficiency, Nuclearsmall module reactor(SMR), and Hydrogen CT. The candidate hydrogen resource modeled in the IRP represents the procurement of new hydrogen CTs. Other components required for the hydrogen economy, including pipelines, storage reservoirs, electrolyzers, and dedicated renewable electricity to run the electrolyzers, are bundled into the hydrogen fuel cost, discussion in the Fuel Prices section.

SVP’s portfolio of existing thermal units is assumed to undergo retrofits or conversions to zero‐emission fuels in the emerging technology scenarios:
 Lodi Energy Center (LEC) – LEC is assumed to undergo a two‐phase retrofit to transition from natural gas to hydrogen by 2035. The first phase occurs in 2027 where a 45% hydrogen fuel blend is assumed. This first phase occurs in all model scenarios, not just the Zero Emissions Scenario. In the second phase, the system is assumed to switch to 100% hydrogen combustion beginning in 2032. Since this is a planned conversion, no costs are modeled for this retrofit.  Alameda CT 1 and 2 – These units are assumed to retrofit to 100% hydrogen starting in 2030. The conversion is a forced‐in decision, and the costs of the retrofit are included in the total system cost.
 Lodi CT – Lodi CT is assumed to retrofit to 100% hydrogen in 2032. The conversion is a forced‐in decision, and the costs of the retrofit are included in the total system cost.  DVR Hydrogen – DVR is assumed to undergo a retrofit for hydrogen fuel combustion in 2035. The conversion is represented as a forced‐in decision, and the costs of the retrofit are included in the total system cost.
 Gianera 1 and 2 – These units are assumed to switch fuels from natural gas to RNG, beginning in 2035. Apart from an increased fuel price and the ending of carbon emissions, no other costs or impacts of the fuel switch are modeled.

Key metrics for the emerging technology resources available to SVP are summarized in Figure 44 and Figure 45.

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Figure 44. Emerging Technology Resource Options
Resource Name First Available Year Cumulative Build
Limit Lifetime (years)
Allam Cycle 100% CCS 2036 Uncapped 25
Nuclear SMR 2036 Uncapped 25
Hydrogen CT 2035 Uncapped 25
Lodi Energy Center (LEC)
2027 – 45% Fuel Blend (modeled in all
scenarios)
2032 – 100% Hydrogen (Zero
Emissions Scenario and Hydrogen
Sensitivity only)
‐‐ ‐‐
Alameda CT 1 Hydrogen 2030 – Retrofit ‐‐  25
Alameda CT 2 Hydrogen 2030 – Retrofit ‐‐  25
Lodi CT Hydrogen 2032 – Retrofit ‐‐  25
DVR Hydrogen 2035 – Retrofit ‐‐  25
Gianera 1 RNG 2035 – Fuel Switch  ‐‐ ‐‐
Gianera 2 RNG 2035 – Fuel Switch ‐‐  ‐‐
Figure 45. Emerging Technology Operating Parameters
Resource Name
Heat Rate Curve VO&M
($/MWh) Intercept Fuel Type Pmin
(MMBtu)
Slope
(MMBtu/MWh)
Allam Cycle 100% CCS 1,624 6.3 5.09 Spot Gas 50%
Nuclear SMR 0 10.0 3.38 Uranium 40%
Hydrogen CT 346 6.1 6.96 Hydrogen ‐‐
Lodi Energy Center (LEC)
Load points
provided by
SVP
Load points
provided by
SVP 3.66
Spot Gas (2024‐26)
Hydrogen 45% Blend
(2027‐2031)
Hydrogen (2032+)
‐‐
Alameda CT 1 Hydrogen
Load points
provided by
SVP
Load points
provided by
SVP

1.52 Spot Gas (2024‐2029)
Hydrogen (2030+) ‐‐
Alameda CT 2 Hydrogen
Load points
provided by
SVP
Load points
provided by
SVP

1.52 Spot Gas (2024‐2029)
Hydrogen (2030+) ‐‐
Lodi CT Hydrogen
Load points
provided by
SVP
Load points
provided by
SVP

1.52 Spot Gas (2024‐2031)
Hydrogen (2032+) ‐‐
DVR Hydrogen
Load points
provided by
SVP
Load points
provided by
SVP

3.00 Spot Gas (2024‐2034)
Hydrogen (2035+) ‐‐
Gianera 1
Load points
provided by
SVP
Load points
provided by
SVP

3.00 Spot Gas (2024‐2034)
RNG (2035+) ‐‐
Gianera 2
Load points
provided by
SVP
Load points
provided by
SVP

3.00 Spot Gas (2024‐2034)
RNG (2035+) ‐‐

7.2. Candidate Resource Costs
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The total fixed costs of candidate resources, including capital cost, FO&M costs, interconnection, investment tax credits (ITCs), property taxes, and warranty and augmentation costs, if any, were derived from the 2023 NREL ATB Electricity report.41 These costs on a $/kW basis were then levelized using a nominal developer weighted average cost of capital (WACC) over the resource’s economic life.

Additionally, transmission cost adders for out‐of‐state resources, discussed in the Transmission section, are added to this value to determine the Levelized Fixed Cost (LFC). In PLEXOS, the Build Cost parameter represents the levelized cost inputs from NREL ATB plus any transmission deliverability cost adders. The sum of these values yields LFC for each candidate resource.

The IRA is expected to impact the costs of candidate clean energy resources. These impacts are largely due to existing tax credits extending beyond 2024 and new technology‐neutral tax credits that will begin in 2025. Due to the IRA, solar PV can elect to receive a PTC instead of the ITC. Early analysis suggests that the PTC will outperform the ITC for utility‐scale solar projects. Therefore, new candidate solar resources are assumed to elect the PTC. In addition, standalone storage projects are now eligible for the ITC under the IRA. Projects are eligible for the full “Bonus” tax credit amounts (30% of qualifying capital expenditure forthe ITC or $26/MWh of electricity generation forthe PTC) ifspecific prevailing wage and apprenticeship requirements are met. If these requirements are not met, the project is eligible for one‐fifth of the full tax credit amount. The full “Bonus” IRA tax credits will be used to calculate resource costs.

Emerging clean energy technologies such as hydrogen and CCS are eligible for new tax credits under the IRA for systems that produce green electrofuels and thermal generators equipped with CCS technologies.

Systems are eligible for these PTCs until 2032, which can be extended to 2035 using a three‐year assumption for Continuity Safe Harbor. The PTC for hydrogen CTs and retrofits built in 2035 is factored into the hydrogen fuel price, discussed in a later section. For Allam Cycle 100% CCS, since the resource is not available until 2036, no PTC is modeled.

Inflationary pressures and supply chain issues have caused price increases for certain metals and other raw materials which may drive up the costs for some technologies. Studies have shown that since 2020, renewable technologies such as wind, solar, and lithium‐ion batteries have seen increases in Levelized Cost of Energy (LCOE) and overnight capital expenditure (CAPEX). Modifications to the NREL ATB cost trajectory for utility‐scale solar, onshore wind, offshore wind, and Li‐ion batteries were made to reflect current market conditions and substantial impacts to the supply chain.

Although new emitting thermal generation is not allowed in the scenarios considered, the LFCs for candidate thermal resources are summarized in Figure 46 for reference. 41 https://atb.nrel.gov/electricity/2023/index
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Figure 46. Candidate Thermal Resource Levelized Fixed Costs, 2022 $/kW‐yr Resource Name 2026 2028 2030 2032 2035
Advanced CCGT $187.37 $184.31 $181.24 $178.16 $173.43
Aero CT $187.14 $184.64 $182.00 $179.36 $175.60
Reciprocating Engine $187.14 $184.64 $182.00 $179.36 $175.60 For candidate renewable resources, the LCOE is derived from the LFC using the annual capacity factor, plus any VO&M cost, fuel cost, and PTCs, if applicable. The LCOE represents the volumetric cost of electricity required for the candidate resource to recover its variable and fixed costs. The LCOEs of candidate renewable resources are summarized in Figure 47.

Figure 47. Levelized Cost of Electricity by Candidate Renewable Technology, 2022 $/MWh LFCs for candidate energy storage and emerging technologies are derived from NREL ATB and the CPUC IRP I&A documentation. LFCs are provided in Figure 48 and Figure 49 for storage and emerging technologies, respectively. Note that in the Geothermal Limitations and Hydrogen Challenges Sensitivity, the cost of hydrogen retrofits are doubled relative to what is presented in Figure 49.

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Figure 48 Candidate Storage Resource Levelized Fixed Costs, 2022 $/kW‐yr Figure 49. Candidate Emerging Technology Levelized Fixed Cost, 2022 $/kW‐yr Portfolio Expansion Resource Options2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   86

7.3. Reliability Requirement Assumptions
The reliability contribution from candidate resources was determined using a marginal ELCC accounting framework as discussed in Section 6.4. The marginal ELCCs by technology and year are provided in Figure 31 of Section 6.4.

7.4. Fuel Prices
Several fuels are modeled for the thermal resources in SVP’s existing and planned resource portfolio, as well as for candidate and planned emerging technology resources in Scenario 3: Zero Emissions with Emerging Technology (Zero Emissions Scenario) and the Geothermal Limitations and Hydrogen Challenges Sensitivity (Hydrogen Sensitivity). These fuels include natural gas, RNG, hydrogen, and uranium, shown in Figure 50. See Appendix C for hydrogen fuel price assumptions.

Figure 50. Fuels Included in the SVP IRP Model
Fuel Generators Data Source
Natural Gas Existing thermal fleet
Candidate thermal resources
E3 Gas Price Forecast
Hydrogen Blend Lodi Energy Center (from 2027) 45%/55% Blend of Natural Gas and Hydrogen fuel prices
Hydrogen*
Candidate Hydrogen CT
Alameda CT 1 and 2 (from 2030)
Lodi CT (from 2032)
Lodi Energy Center (from 2032)
DVR (from 2035)
E3 Electrofuels Calculator
Renewable Natural Gas* Gianera 1 and 2 (from 2035) SVP price estimate Uranium* Candidate Nuclear SMR CPUC IRP Inputs & Assumptions * Only modeled in the Zero Emissions Scenario and Hydrogen Sensitivity SVP’s existing portfolio of thermal‐fired units are assumed to use natural gassettled at the PG&E City Gate spot gas price. The price forecast was developed by E3 using a combination of forward prices in the near‐ term42 and Energy Information Administration Annual Energy Outlook fundamentals‐based forecasts for the longer term.43 The price forecasts were localized to the PG&E Gate using projections of monthly basis differentials from the near‐term forward prices. The resulting spot gas price forecast is shown in Figure

51. 42 Henry Hub forwards from S&P Global Market Intelligence, https://www.spglobal.com/marketintelligence/en/.   43 https://www.eia.gov/outlooks/aeo/.

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Figure 51. Natural Gas Price Forecast, 2022 $/MMBtu
The hydrogen fuel price forecast, shown in Figure 52, was calculated using E3’s Hydrogen Calculator.

Hydrogen fuel prices are levelized and vintaged by generator construction year due to the hydrogen PTC.

In the Geothermal Limitations and Hydrogen Challenges Sensitivity, hydrogen fuel prices are increased to reflect an upper bound of uncertainty over future fuel prices. For details on hydrogen forecast assumptions, see Appendix C.

Figure 52. Hydrogen Price Forecast, 2022 $/MMBtu
A RNG price assumption of $30/MMBtu in 2035 was provided by SVP for Gianera 1 and 2.

A uranium fuel price of $0.71/MMBtu in real 2022 dollars was adopted from the CPUC IRP Inputs and Assumptions document.44
44 https://www.cpuc.ca.gov/industries‐and‐topics/electrical‐energy/electric‐power‐procurement/long‐term‐procurement‐ planning/2022‐irp‐cycle‐events‐and‐materials
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7.5. Transmission
As discussed in Section 6, the two regions in the SVP IRP model represent the SVP metered subsystem (MSS) and the rest of CAISO. These two nodes are connected by a transmission line that represents SVP’s tie‐ins to the bulk CAISO system. Per SVP’s MSS agreement, SVP must pay a TAC on net imports over this line. In PLEXOS, this consideration is instead implemented by applying a discount, equal to the TAC, on DVR and Gianera 1 and 2, such that these resources are incentivized to dispatch as resources that reduce SVP’s net load. The TAC is then added back in as a post‐processing step to calculate total system costs.

Here, the TAC is applied to SVP’s total load.

The forecast of high‐voltage and low‐voltage TAC was provided by a consultant supporting SVP and is provided in Figure 53.

Figure 53. TAC Forecast, 2022 $/MWh
Two out‐of‐state resources, Wyoming Wind and New Mexico Wind, are located external to the CAISO system. Instead of modeling these remote candidate resources in separate zones within PLEXOS to simulate the full transmission network, the transmission considerations have been modeled implicitly:
 The availability of remote candidate resources is delayed reflecting the expected timelines for additional capability to be made available on specific transmission lines, aligned with the latest assumptions from the CPUC IRP Inputs and Assumptions document.45  Cost adders have been assigned to specific candidate resources based on the need for line upgrades to accommodate additional transmission capability. These are included in the resource “Build Cost” in the PLEXOS model.
45 https://www.cpuc.ca.gov/industries‐and‐topics/electrical‐energy/electric‐power‐procurement/long‐term‐procurement‐ planning/2022‐irp‐cycle‐events‐and‐materials
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Out‐of‐state resources are assumed to require new transmission connections to the CAISO system. These connections incur out‐of‐state transmission deliverability costs which include transmission upgrade costs and wheeling charges. Transmission cost data for these remote wind generators are summarized in Figure

54. Figure 54. Transmission Deliverability Costs, 2022 $/kW‐yr Resource Name Upgrade Cost Wheeling Charge Notes
New Mexico Wind $71.20 $30.78 SunZia46 + SRP Wheeling47 Wyoming Wind $118.80 N/A TransWest48
46 https://nmfwri.org/wp‐content/uploads/2022/02/Mountainair‐Collaborative_SunZia‐Update‐1‐27‐2022.pdf. 47 http://www.oasis.oati.com/woa/docs/SRP/SRPdocs/SRP_OATT_08‐01‐2022_Final.pdf. 48 https://www.energy.ca.gov/reti/.

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8.Results and Discussion
This section presents the SVP system resource portfolios in three scenarios with varying clean energy requirements from 2026, the first year when new resource additions are allowed, to 2035, the end of the planning horizon. The three scenarios are listed in order of least to most stringent clean energy requirements:
 Scenario 1: Base SB 100
 Scenario 2: Accelerated SB 100
 Scenario 3: Zero Emissions with Emerging Technology
Scenario 1: Base SB 100 (Base Scenario) identifies the optimal least‐cost portfolio that meets the current state policies. Scenario 2: Accelerated SB 100 (Accelerated SB 100 Scenario) advances the statewide SB 100 targets from the Base Scenario to reach 100% of retail sales clean by 2035. Scenario 3: Zero Emissions with Emerging Technology (Zero Emissions Scenario) achieves zero hourly emissions in 2035 with emerging technologies. For detailed scenario assumptions, please refer to Section 6.6.

The following Sections 8.1, 8.2, and 8.3 summarize results in each of the scenarios. Section 8.4 compares the three scenarios to identify the impacts of more aggressive clean energy policies.

The accompanying CEC Standardized Tables (CRAT, EBT, RPT, and GEAT) for the three scenarios are included in Appendix D.

8.1. Scenario 1: Base SB 100
Figure 55 shows the cumulative resource additions through 2035 in Scenario 1: Base SB 100 (Base Scenario). In the period 2026‐2027, SVP is modeled to add 180 MW wind, 150 MW solar, and 110 MW battery storage capacity to meet load growth and reliability requirements. Starting in 2028, geothermal becomes available and is added to the system (as well as wind capacity) as geothermal, though higher cost per MWh than wind, provides both clean energy generation and firm capacity that carries a higher reliability contribution. The baseload operating characteristics of geothermal also align with the relatively high 80% load factor (or average load divided by peak load) of the SVP system. A high load factor means that the system demand is relatively constant. Due to the large share of industrial load on SVP’s system and forecasted data center load growth, there is less ability to shape loads to take advantage of certain resource production, such as low‐cost solar. By 2035, the total resource additions include 290 MW geothermal, 590 MW wind, 150 MW solar, and 110 MW storage capacity to meet load growth and the increasing clean energy requirement.

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Figure 55. Base Scenario Cumulative New Build Capacity
Figure 56 shows the total capacity through 2035 in the Base Scenario. In addition to resource additions in the new build capacity, this figure includes SVP’s existing and planned resources. Renewable and zero‐ carbon resources make up an increasing share of the total system capacity as no new emitting fossil fuel resources can be added to the system. One of the existing gas resources, LEC (78 MW), also transitions from 100% natural gas to 45% (volumetric) hydrogen blending. For detailed assumptions on existing and planned resources, please refer to Section 4 Existing and Planned System and Resources.

Figure 56. Base Scenario Total Capacity
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Figure 57 shows the annual generation by resource type through 2035 in the Base Scenario. With existing, planned, and new build renewable resources, RPS (as a % of retail sales) reaches slightly over 60% in 2026, four years ahead of the 60% by 2030 SB 100 target and increases to around 80% by 2035.

Zero‐carbon resource generation (as a percentage of retail sales) reaches an estimated 77% in 2026 and increases to 90% in 2035, meeting SB 100 interim targets. Despite significant load growth forecasted over the planning period, gas‐based generation gradually reduces and stays relatively consistent in later years, as clean energy generation is selected to meet new loads.

Figure 57. Base Scenario Annual Generation
Note: RPS and Zero Carbon percentages are based on retail sales and on the accounting framework of annual targets in SB 100
Figure 58 details the annual energy balance of loads and resources.

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Figure 58. Base Scenario Annual Energy Balance of Loads and Resources Figure 59 shows the system reliability modeling results through 2035 in the Base Scenario, using SVP’s marginal reliability need and marginal ELCC MW values. While the marginal ELCC per nameplate capacity of some resources such as gas and geothermal remains high, that of other resources such as wind, solar, and battery storage is lower and declines over the planning horizon as large volumes of these resources are added by other CAISO LSEs. Therefore, even with a relatively large share of the total nameplate Technology 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 6,436 7,037 7,492 7,964 8,428 8,953 9,210 9,387 9,559 5,983 DVR Gas - CC 1,195 1,214 1,163 1,036 1,012 1,005 1,034 1,041 1,103 946 Gianera 1 Gas - CT 10 10 7 3 7 5 - 10 0 1
Gianera 2 Gas - CT 10 10 5 4 4 5 - - 10 0
Alameda CT 1 Gas - CT - - - - - - - - - -
Alameda CT 2 Gas - CT - - - - - - - - - -
Lodi CT Gas - CT - - - - - - - - - -
LEC Gas - CC - - - - - - - - - 284
LEC Hydrogen 45 Blend Hydrogen Blend - 254 257 214 76 108 67 16 78 93 Collierville Large Hydro 158 15 158 158 158 158 158 158 158 158 8 BESS 50MW 200MWh Li-ion Battery (4-hr) (7) (6) (7) (7) (10) (11) (13) (13) (11) (13) Black Butte Small Hydro 8 8 8 8 8 8 8 8 8 8
Stony Gorge Small Hydro 7 7 7 7 7 7 7 7 7 6
Grizzly Hydro Small Hydro 43 43 43 43 43 43 43 43 43 43 Big Horn 1 Wind - - - - - - - - - 209
Big Horn 2 Wind 40 42 37 37 42 36 35 37 28 41
Geo Plant 1 Unit 1 Geothermal 105 105 105 105 105 105 105 105 105 105 Geo Plant 1 Unit 2 Geothermal 105 105 105 105 105 105 105 105 105 105 Geo Plant 2 Unit 4 Geothermal 140 141 140 1 140 40 140 141 140 140 140 Spicer Small Hydro 5 5 5 5 5 5 5 5 5 5
2,074 2,098 1,990 1,716 1,733 2,221 1,678 1,644 1,717 1,626 Tri-Dam Donnells Large Hydro 243 243 243 243 243 243 243 243 243 243 WAPA Base Resource Large Hydro 250 250 250 250 250 250 250 250 250 250 South Feather - Forbstown Large Hydro 60 59 57 58 60 58 59 60 57 59 South Feather - Woodleaf Large Hydro 100 99 98 95 99 100 98 95 95 99 Ameresco Forward Biogas 37 37 37 36 37 36 36 6 - 37
Ameresco Vasco Biogas 38 38 38 37 37 37 37 6 - 38
G2 Landfill Biogas - - - - - - - - - -
Tri-Dam Beardsley Small Hydro 44 45 45 44 45 44 44 43 43 43 Tri-Dam Sand Bar Small Hydro 74 73 75 73 75 74 73 70 70 71 Tri-Dam Tulloch Small Hydro 109 108 108 108 110 110 108 106 106 111 Friant 1 Small Hydro 67 66 66 65 66 66 66 65 65 66
Friant 2 (Quinten) Small Hydro 39 39 39 39 40 39 39 38 38 39 Rio Bravo (Index+) Small Hydro 15 14 14 14 15 14 13 15 14 15 Camp Far West Hydro (Index+) Small Hydro 26 24 26 25 25 25 26 25 26 26 South Feather - Kelly Ridge Small Hydro 27 27 28 27 27 27 27 27 27 27 South Feather - Sly Creek Small Hydro 14 14 14 14 14 14 14 1 14 14 4 Central 40 Solar Solar 113 110 111 112 113 107 109 111 110 113 Rosamond Solar Solar 63 61 62 62 62 60 61 63 60 63
Aquamarine Westside (Index+) Solar - - - - - - - - - -
Manzana Wind Wind 125 116 119 128 126 125 - - - 132
Cimmaron Wind Wind 786 742 783 886 820 855 786 797 761 930 Calpine Geo Geothermal 613 615 613 613 613 615 613 613 613 307 Sand Hill A Wind 28 29 28 28 29 30 26 27 30 30
Sand Hill B Wind 38 39 38 37 39 40 36 37 40 41
Rooney Ranch Wind 41 43 41 41 42 43 39 40 43 44
2,795 2,949 2,891 2,931 3,034 2,986 3,012 2,804 2,751 2,705 New Resources (NonRPS Eligible) Li_Battery_4hr Li-ion Battery (4-hr) (10) (10) (12) (13) (17) (19) (23) (20) (21) (22) Central_California_Wind Wind - - 256 471 471 560 561 569 948 - Geothermal Geothermal - 466 465 1,026 - 1,397 2,012 2,482 2,508 2,541 New_Mexico_Wind Out-of-state Wind 432 415 437 514 525 505 484 486 562 500 Southern_California_Solar Solar 442 426 438 442 450 426 440 443 424 438 Wyoming_Wind Out-of-state Wind - 328 354 615 683 674 640 662 695 703 1,176 1,672 2,275 3,130 3,479 860 4,098 4,610 4,756 5,096 560 728 671 483 653 612 613 633 609 407
(322) (352) (375) (399) (422) (448) (461) (470) (478) (300) 237 37 107 296 6 84 231 164 152 163 131
6,436 7,037 7,492 7,964 8,428 5,983 8,953 9,210 9,387 9,559 Annual Energy Balance of Loads and Resources
Silicon Valley Power
Description
System Annual Energy Demand (GWh)
SVP Owned Units - Generation (GWh)
Long-term Contracts
(RPS Eligible)
Total Long-term Contracts (GWh)
New Resource Additions - Generation (GWh)
SVP Owned Units
(Non-RPS Eligible)
SVP Owned Units
(RPS Eligible)
Total SVP Owned Units (GWh)
Long-Term Contracts - Generation (GWh)
Long-term Contracts
(Non-RPS Eligible)
Net System Energy (GWh)
New Resources
(RPS Eligible)
Total New Resource Additions (GWh)
Market Purchases and Sales (GWh)
Market Purchases (GWh)
Market Sales (GWh)
Net Market Purchases (GWh)
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capacity, solar, wind, and battery storage only contribute to a small share of the total effective capacity need. Geothermal, existing gas and hydro remain important for system reliability throughout the planning horizon.

The marginal reliability need shown in Figure 59 is not as high as peak load plus a margin as in the traditional PRM approach and it does not necessarily increase. However, it should not be directly interpreted as meaning there are lower capacity needs for the system, because the corresponding marginal ELCCs used for resource accreditation are also lower than the average ELCCs used in the traditional PRM approach. Hence, relative to the traditional PRM planning approach, the need declines but the resource contributions also decline accordingly. Although not directly used in modeling, the estimated total reliability need, using the traditional framework, and the difference in resource capacity accreditation (“CAISO Portfolio Effects”) is included in the reliability figure for illustrative purposes.49 For more details on the marginal reliability framework, please refer to Section 6.4 Model Constraints.

Figure 59. Base Scenario Marginal Reliability Need and Marginal Effective Capacity Figure 60 details the annual marginal reliability need and resource capacity. 49 The total reliability need is estimated based on SVP’s coincident load with CAISO’s gross peak in the 2022 IEPR forecast and a perfect capacity (PCAP)‐based PRM of 14%. Gross peak is CAISO’s managed net peak with all BTM PV’s load‐reducing impacts added back. The 14% PCAP PRM translates to about 22% ICAP PRM and is a more stringent target than previous CAISO studies to ensure a 1‐day‐in‐10‐years LOLE target.

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Figure 60. Base Scenario Marginal Reliability Need and Resource Capacity Accreditation Technology 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 906 987 1,056 845 1,124 1,186 1,251 1,287 1,315 1,341
System Coincident Peak(Coincident with 2022 IEPR CAISO Gross Peak) 790 843 858 952 1,010 1,085 1,164 1,163 1,144 1,210 PCAP PRM (%) 14% 14% 14% 14% 14% 14% 14% 14% 14% 14%
System Total Reliability Need (MW) 961 979 1,085 900 1,152 1,237 1,326 1,326 1,304 1,380 CAISO Portfolio Effects (MW) 107 116 203 243 300 333 370 334 432 76 853 863 882 909 937 993 956 970 947 825
DVR Gas - CC 129 129 127 126 128 129 131 133 135 130
Gianera 1 Gas - CT 20 20 20 20 20 20 20 21 21 21
Gianera 2 Gas - CT 20 20 20 20 20 20 20 21 21 21
Alameda CT 1 Gas - CT 8 8 8 8 8 8 8 8 8 8
Alameda CT 2 Gas - CT 8 8 8 8 8 8 8 8 8 8
Lodi CT Gas - CT 8 8 8 8 8 8 8 8 8 8
LEC Gas - CC - - - - - - - - - 68
LEC Hydrogen 45 Blend Hydrogen Blend - 68 68 67 66 67 68 69 70 71 Collierville Large Hydro 49 46 45 44 43 42 41 40 39 51
BESS 50MW 200MWh Li-ion Battery (4-hr) 46 42 39 38 37 34 30 27 23 20 Black Butte Small Hydro 2 2 2 2 2 2 2 2 2 2
Stony Gorge Small Hydro 2 2 2 2 2 2 2 2 2 2
Grizzly Hydro Small Hydro 7 6 6 6 6 6 6 6 5 7
Big Horn 1 Wind - 23 - - - - - - - -
Big Horn 2Wind4 4 4 3 3 3 3 3 3 3
Geo Plant 1 Unit 1 Geothermal 11 11 11 11 11 11 11 11 11 11 Geo Plant 1 Unit 2 Geothermal 11 11 11 11 11 11 11 11 11 11 Geo Plant 2 Unit 4 Geothermal 15 15 15 15 15 15 15 15 15 14 Spicer Small Hydro 1 1 1 1 1 1 1 1 1 1
406 399 392 386 385 384 384 383 382 436
Tri-Dam Donnells Large Hydro 38 36 35 35 34 33 32 32 31 40 WAPA Base Resource Large Hydro 67 63 62 61 59 58 57 55 54 71 South Feather - Forbstown Large Hydro 13 12 12 13 1 11 11 11 11 10 2 South Feather - Woodleaf Large Hydro 20 19 19 19 18 18 17 17 17 22 Ameresco Forward Biogas 3 3 3 3 3 3 3 - - 3
Ameresco Vasco Biogas 3 3 3 3 3 3 4 - - 3
G2 Landfill Biogas - - - - - - - - - -
Tri-Dam Beardsley Small Hydro 4 4 4 4 4 4 4 4 4 5
Tri-Dam Sand Bar Small Hydro 6 6 6 6 5 5 5 5 5 7
Tri-Dam Tulloch Small Hydro 10 9 9 9 9 9 8 8 8 10
Friant 1 Small Hydro 10 9 9 9 8 8 8 8 8 10
Friant 2 (Quinten) Small Hydro - - - - - - - - - -
Rio Bravo (Index+) Small Hydro 5 5 5 5 5 5 5 4 4 6
Camp Far West Hydro (Index+) Small Hydro 3 2 2 2 2 2 2 2 2 3 South Feather - Kelly Ridge Small Hydro 3 3 2 2 2 2 2 2 2 3 South Feather - Sly Creek Small Hydro 3 3 3 3 3 3 3 3 3 3 Central 40 Solar Solar 4 4 3 2 2 2 2 3 3 4
Rosamond Solar Solar 2 2 2 1 1 1 1 1 1 2
Aquamarine Westside (Index+) Solar - - - - - - - - - -
Manzana Wind Wind 6 4 4 4 4 3 - - - 8
Cimmaron Wind Wind - - - - - - - - - -
Calpine Geo Geothermal 64 65 65 64 65 65 66 66 67 31
Sand Hill A Wind 3 2 2 2 2 2 2 1 1 4
Sand Hill B Wind 4 3 3 3 3 2 2 2 2 5
Rooney Ranch Wind 5 3 3 3 3 3 2 2 2 6
277 262 257 252 248 244 237 226 222 260
New Resources (NonRPS Eligible) Li_Battery_4hr Li-ion Battery (4-hr) 79 92 84 83 81 74 66 59 51 44 Central_California_Wind Wind - - - 8 12 11 12 11 9 14
Geothermal Geothermal - 49 49 108 148 215 268 272 279 - New_Mexico_Wind Out-of-state Wind 34 36 37 34 26 27 29 30 32 33 Southern_California_Solar Solar 15 14 12 9 9 9 9 9 10 16 Wyoming_Wind Out-of-state Wind - 28 29 47 35 37 39 41 43 45 171 214 233 271 307 370 418 417 425 129
853 875 882 909 940 999 825 1,039 1,026 1,030
New Resources
(RPS Eligible)
Total New Resource Additions (MW)
Total System Marginal ELCC Capacity (MW)
Long-term Contracts
(Non-RPS Eligible)
Long-term Contracts
(RPS Eligible)
Total Long-term Contracts (MW)
New Resource Additions - Marginal Effective Load Carrying Capability, ELCC (MW) SVP Owned Units - Marginal Effective Load Carrying Capability, ELCC (MW) SVP Owned Units
(Non-RPS Eligible)
SVP Owned Units
(RPS Eligible)
Total SVP Owned Units (MW)
Long-Term Contracts - Marginal Effective Load Carrying Capability, ELCC (MW) Marginal Reliability Need and Resource Capacity Accreditation Silicon Valley Power
Description
System Non-Coincident Peak Demand (MW)
System Marginal Reliability Need (MW)
Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   96

8.2. Scenario 2: Accelerated SB 100
The Accelerated SB 100 Scenario builds on top of Scenario 1: Base SB 100 (Base Scenario) to accelerate the SB 100 targets from 60% RPS to 70% carbon‐free energy (60% still needs to come from renewable resources) by 2030, and from 90% carbon‐free energy to 100% by 2035.

Figure 61 shows the cumulative resource additions through 2035 in the Accelerated SB 100 Scenario.

Near‐term additions are similar to those in the Base Scenario prior to the accelerated clean energy targets driving decisions later in the horizon. By 2035, the total resource additions include 330 MW geothermal, 740 MW wind, 180 MW solar, and 100 MW battery storage. 40 MW more geothermal, 150 MW more wind, and 30 MW more solar are selected compared to the Base Scenario to meet the higher clean energy requirement. Figure 62 shows the total capacity, including existing and planned resources, through 2035.

Figure 61. Accelerated SB 100 Scenario Cumulative New Build Capacity Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   97
Figure 62. Accelerated SB 100 Scenario Total Capacity
Figure 63 showsthe annual generation by resource type through 2035 in the Accelerated SB 100 Scenario.

With existing, planned, and new build resources, carbon‐free resource generation (as a percentage of retail sales) surpasses the 70% target in 2030, as clean energy generation is selected to meet SVP’s large increase in retailsales, and increasesto 100%, meeting the accelerated 2035 target. Gas‐based generation is lower than that in the Base Scenario, but still present as the clean energy requirement is based on the accounting framework of SB 100, which requires 100% clean energy generation of retail sales, not total generation.

Figure 63. Accelerated SB 100 Scenario Annual Generation Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   98
Note: RPS and Zero Carbon percentages are based on retail sales and based on the accounting framework of annual targets in SB 100
Figure 64 details the annual energy balance of loads and resources.

Figure 64. Accelerated SB 100 Scenario Annual Energy Balance of Loads and Resources Technology 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 6,436 7,037 7,492 7,964 8,428 8,953 9,210 9,387 9,559 5,983 DVR Gas - CC 1,152 1,193 1,139 1,026 1,007 1,005 1,020 1,056 876 508 Gianera 1 Gas - CT 10 10 6 1 5 5 - - - 10
Gianera 2 Gas - CT 10 10 4 3 5 5 - - - 10
Alameda CT 1 Gas - CT - - - - - - - - - -
Alameda CT 2 Gas - CT - - - - - - - - - -
Lodi CT Gas - CT - - - - - - - - - -
LEC Gas - CC - - - - - - - - - 274
LEC Hydrogen 45 Blend Hydrogen Blend - 237 236 188 57 111 65 15 22 38 Collierville Large Hydro 158 158 158 158 158 158 158 158 158 158 BESS 50MW 200MWh Li-ion Battery (4-hr) (8) (6) (7) (8) (11) (12) (13) (12) (13) (38) Black Butte Small Hydro 8 8 8 8 8 8 8 8 8 8
Stony Gorge Small Hydro 7 7 7 7 7 7 7 7 7 6
Grizzly Hydro Small Hydro 43 43 43 43 43 43 43 43 43 43 Big Horn 1 Wind - - - - - - - - - 208
Big Horn 2 Wind 40 42 37 37 42 36 35 37 27 41
Geo Plant 1 Unit 1 Geothermal 105 105 105 105 105 105 105 105 105 105 Geo Plant 1 Unit 2 Geothermal 105 105 105 105 105 105 105 105 105 105 Geo Plant 2 Unit 4 Geothermal 140 141 140 140 140 140 141 140 140 140 Spicer Small Hydro 5 5 5 5 5 5 5 5 5 5
2,014 2,056 1,938 1,686 1,729 2,163 1,676 1,630 1,493 1,107 Tri-Dam Donnells Large Hydro 243 243 243 243 243 243 243 243 243 243 WAPA Base Resource Large Hydro 250 250 250 250 250 250 250 250 250 250 South Feather - Forbstown Large Hydro 60 59 57 59 60 58 59 60 57 59 South Feather - Woodleaf Large Hydro 100 99 98 97 99 101 98 95 94 99 Ameresco Forward Biogas 37 37 37 37 37 36 36 6 - 37
Ameresco Vasco Biogas 38 38 38 37 37 37 37 6 - 38
G2 Landfill Biogas - - - - - - - - - -
Tri-Dam Beardsley Small Hydro 44 45 45 44 45 44 44 43 43 43 Tri-Dam Sand Bar Small Hydro 74 73 75 73 75 74 73 70 70 71 Tri-Dam Tulloch Small Hydro 109 108 108 108 110 110 108 106 106 111 Friant 1 Small Hydro 67 66 66 65 66 66 66 65 65 66
Friant 2 (Quinten) Small Hydro 39 39 39 39 40 39 39 38 38 39 Rio Bravo (Index+) Small Hydro 15 14 14 14 15 14 13 15 14 15 Camp Far West Hydro (Index+) Small Hydro 26 24 26 25 25 25 26 25 26 26 South Feather - Kelly Ridge Small Hydro 27 27 28 27 27 27 27 27 26 26 South Feather - Sly Creek Small Hydro 14 14 14 14 14 14 14 14 1 13 4 Central 40 Solar Solar 113 110 111 112 113 107 107 110 103 113 Rosamond Solar Solar 63 61 62 62 62 59 61 62 55 62
Aquamarine Westside (Index+) Solar - - - - - - - - - -
Manzana Wind Wind 125 116 119 128 127 123 - - - 131
Cimmaron Wind Wind 786 742 783 886 822 851 777 794 732 930 Calpine Geo Geothermal 613 615 613 613 613 615 613 613 613 307 Sand Hill A Wind 28 29 28 28 29 29 26 27 28 30
Sand Hill B Wind 38 39 38 38 39 40 36 37 37 41
Rooney Ranch Wind 41 43 41 41 42 43 39 40 41 44
2,792 2,949 2,891 2,931 3,039 2,988 3,005 2,792 2,747 2,654 New Resources (NonRPS Eligible) Li_Battery_4hr Li-ion Battery (4-hr) (11) (10) (12) (13) (17) (20) (21) (20) (21) (33) Central_California_Wind Wind - - 256 389 390 526 527 534 1,242 - Geothermal Geothermal - 466 465 1,045 - 1,389 1,961 2,447 2,869 2,821 New_Mexico_Wind Out-of-state Wind 445 427 450 534 545 524 502 505 584 520 Southern_California_Solar Solar 529 511 524 530 539 510 528 531 508 525 Wyoming_Wind Out-of-state Wind - 328 354 615 683 674 640 662 695 938 1,275 1,769 2,382 3,176 3,497 959 4,118 4,649 5,193 5,995 520 674 616 463 637 601 601 425 281 369
(322) (352) (375) (399) (422) (448) (461) (470) (478) (300) 198 69 241 322 64 214 153 140 (45) (198)
Net System Energy (GWh) 6,436 7,037 7,492 7,964 8,428 5,983 8,953 9,210 9,387 9,559 New Resources
(RPS Eligible)
Total New Resource Additions (GWh)
Market Purchases and Sales (GWh)
Market Purchases (GWh)
Market Sales (GWh)
Net Market Purchases (GWh)
Long-term Contracts
(RPS Eligible)
Total Long-term Contracts (GWh)
New Resource Additions - Generation (GWh)
SVP Owned Units
(Non-RPS Eligible)
SVP Owned Units
(RPS Eligible)
Total SVP Owned Units (GWh)
Long-Term Contracts - Generation (GWh)
Long-term Contracts
(Non-RPS Eligible)
Annual Energy Balance of Loads and Resources
Silicon Valley Power
Description
System Annual Energy Demand (GWh)
SVP Owned Units - Generation (GWh)
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Figure 65 shows the system reliability modeling results through 2035 in the Accelerated SB 100 Scenario.

As more capacity is added to meet the clean energy target in this scenario, the total system marginal ELCC MW is higher than that in the Base Scenario and is above the marginal reliability need towards the end of the planning horizon, which illustrates that the clean energy target is the more stringent requirement to meet.

Figure 65. Accelerated SB 100 Scenario Marginal Reliability Need and Marginal Effective Capacity
Figure 66 details the annual marginal reliability need and resource capacity.

Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   100
Figure 66. Accelerated SB 100 Scenario Marginal Reliability Need and Resource Capacity Accreditation
Technology 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 906 987 1,056 845 1,124 1,186 1,251 1,287 1,315 1,341
System Coincident Peak (Coincident with 2022 IEPR CAISO Gross Peak) 790 843 858 952 1,010 1,085 1,164 1,163 1,144 1,210 PCAP PRM (%) 14% 14% 14% 14% 14% 14% 14% 14% 14% 14%
System Total Reliability Need (MW) 961 979 1,085 900 1,152 1,237 1,326 1,326 1,304 1,380 CAISO Portfolio Effects (MW) 107 116 203 243 300 333 370 334 432 76 853 863 882 909 937 993 956 970 947 825
DVR Gas - CC 129 129 127 126 128 129 131 133 135 130
Gianera 1 Gas - CT 20 20 20 20 20 20 20 21 21 21
Gianera 2 Gas - CT 20 20 20 20 20 20 20 21 21 21
Alameda CT 1 Gas - CT 8 8 8 8 8 8 8 8 8 8
Alameda CT 2 Gas - CT 8 8 8 8 8 8 8 8 8 8
Lodi CT Gas - CT 8 8 8 8 8 8 8 8 8 8
LEC Gas - CC - - - - - - - - - 68
LEC Hydrogen 45 Blend Hydrogen Blend - 68 68 67 66 67 68 69 70 71 Collierville Large Hydro 49 46 45 44 43 42 41 40 39 51
BESS 50MW 200MWh Li-ion Battery (4-hr) 46 42 39 38 37 34 30 27 23 20 Black Butte Small Hydro 2 2 2 2 2 2 2 2 2 2
Stony Gorge Small Hydro 2 2 2 2 2 2 2 2 2 2
Grizzly Hydro Small Hydro 7 6 6 6 6 6 6 6 5 7
Big Horn 1 Wind - - 23 - - - - - - -
Big Horn 2Wind4 4 3 3 3 3 3 3 3 4
Geo Plant 1 Unit 1 Geothermal 11 11 11 11 11 11 11 11 11 11 Geo Plant 1 Unit 2 Geothermal 11 11 11 11 11 11 11 11 11 11 Geo Plant 2 Unit 4 Geothermal 15 15 15 15 15 15 15 15 15 14 Spicer Small Hydro 1 1 1 1 1 1 1 1 1 1
406 399 392 386 385 384 384 383 382 436
Tri-Dam Donnells Large Hydro 38 36 35 35 34 33 32 32 31 40 WAPA Base Resource Large Hydro 67 63 62 61 59 58 57 55 54 71 South Feather - Forbstown Large Hydro 13 12 12 12 13 1 11 11 11 10 1 South Feather - Woodleaf Large Hydro 20 19 19 19 18 18 17 17 17 22 Ameresco Forward Biogas 3 3 3 3 3 3 3 - - 3
Ameresco Vasco Biogas 3 3 3 3 3 3 4 - - 3
G2 Landfill Biogas - - - - - - - - - -
Tri-Dam Beardsley Small Hydro 4 4 4 4 4 4 4 4 4 5
Tri-Dam Sand Bar Small Hydro 6 6 6 6 5 5 5 5 5 7
Tri-Dam Tulloch Small Hydro 10 9 9 9 9 9 8 8 8 10
Friant 1 Small Hydro 10 9 9 9 8 8 8 8 8 10
Friant 2 (Quinten) Small Hydro - - - - - - - - - -
Rio Bravo (Index+) Small Hydro 5 5 5 5 5 5 5 4 4 6
Camp Far West Hydro (Index+) Small Hydro 3 2 2 2 2 2 2 2 2 3 South Feather - Kelly Ridge Small Hydro 3 3 2 2 2 2 2 2 2 3 South Feather - Sly Creek Small Hydro 3 3 3 3 3 3 3 3 3 3 Central 40 Solar Solar 4 4 3 2 2 2 2 3 3 4
Rosamond Solar Solar 2 2 2 1 1 1 1 1 1 2
Aquamarine Westside (Index+) Solar - - - - - - - - - -
Manzana Wind Wind 6 4 4 4 4 3 - - - 8
Cimmaron Wind Wind - - - - - - - - - -
Calpine Geo Geothermal 64 65 65 64 65 65 66 66 67 31
Sand Hill A Wind 3 2 2 2 2 2 2 1 1 4
Sand Hill B Wind 4 3 3 3 3 2 2 2 2 5
Rooney Ranch Wind 5 3 3 3 3 3 2 2 2 6
277 262 257 252 248 244 237 226 222 260
New Resources (NonRPS Eligible) Li_Battery_4hr Li-ion Battery (4-hr) 74 88 81 79 78 70 63 56 49 42 Central_California_Wind Wind - - - 8 10 9 11 10 9 18
Geothermal Geothermal - 49 49 110 148 210 264 312 317 - New_Mexico_Wind Out-of-state Wind 35 37 38 36 27 28 30 31 33 34 Southern_California_Solar Solar 18 17 14 11 11 11 11 11 11 19 Wyoming_Wind Out-of-state Wind - 28 29 47 35 37 39 41 43 60 171 214 233 271 304 365 414 457 484 129
853 875 882 909 937 993 825 1,035 1,066 1,088
New Resources
(RPS Eligible)
Total New Resource Additions (MW)
Total System Marginal ELCC Capacity (MW)
Long-term Contracts
(Non-RPS Eligible)
Long-term Contracts
(RPS Eligible)
Total Long-term Contracts (MW)
New Resource Additions - Marginal Effective Load Carrying Capability, ELCC (MW) SVP Owned Units - Marginal Effective Load Carrying Capability, ELCC (MW) SVP Owned Units
(Non-RPS Eligible)
SVP Owned Units
(RPS Eligible)
Total SVP Owned Units (MW)
Long-Term Contracts - Marginal Effective Load Carrying Capability, ELCC (MW) Marginal Reliability Need and Resource Capacity Accreditation Silicon Valley Power
Description
System Non-Coincident Peak Demand (MW)
System Marginal Reliability Need (MW)
Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   101

8.3. Scenario 3: Zero Emissions with Emerging Technology This scenario represents the most stringent clean energy target modeled in this IRP. Scenario 3: Zero Emissions with Emerging Technology (Zero Emissions Scenario) builds on top of Scenario 2: Accelerated SB 100 and limits emission to zero in every hour in 2035.

As gas plants cannot be dispatched to serve load or meet reliability requirements without resulting in carbon emissions in this scenario, they must either retire or convert to zero‐carbon fuels by 2035.

Additionally, market purchases are only allowed in hours when the market emission factors are zero.

However, emerging technologies are assumed to be available to help achieve zero emissions in this scenario. As many studies have shown, “clean firm” resources that can provide zero‐carbon generation on demand to fill in gapsin variable resource output are a critical component of reaching a zero‐emissions power system. The “clean firm” technologies considered include building new green hydrogen power plants, CCS (Allam cycle with 100% capture and storage) plants, and long‐duration storage. In addition to the ability to build new clean firm resources, retrofits of SVP’s existing thermal portfolio to zero‐emission fuels are assumed:
 LEC transitions from 45% (volumetric) hydrogen blending (2027) to 100% hydrogen starting in 2032 50
 Alameda CT 1 and 2 run on 100% hydrogen starting in 2030  Lodi CT runs on 100% hydrogen starting in 2032
 DVR runs on 100% hydrogen starting in 2035
 Gianera 1 and 2 run on 100% biogas starting in 2035
DVR and Gianera are two significant local SVP resources, and the transition of these resources to zero‐ emission fuelsin 2035 in this scenario is partly driven by transmission limitations between SVP and CAISO.

If local resources aren’t available, SVP may be completely dependent on electricity delivered via transmission from CAISO to meet load. However, the existing and planned transmission capacity would have insufficient capacity and is about 90 MW below SVP’s forecasted peak load in 2035. Therefore, it is not feasible under current and planned transmission additions to reach zero‐emissions without retrofitting local gas generating resources to run on zero‐emission fuel and allow them to be dispatched to meet SVP’s load.

Figure 67 shows the cumulative resource additions through 2035 in the Zero Emissions Scenario. The figure includes the above existing resources’ assumed transitions to zero‐emission fuels. Near‐term additions are similar to the Accelerated SB 100 Scenario’s additions as the zero‐emission limit is not applied until 2035. By 2035, the total resource additions include 280 MW hydrogen (250 MW comes from assumed transitions of DVR and LEC and 30 MW comes from building new hydrogen plants), 350 MW geothermal, 50 MW biogas (assumed transition of Gianera), 530 MW wind, 150 MW solar, and 100 MW 50 The 2032 start year is assumed based on information provided to SVP in communications with NCPA.

Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   102
battery storage. Other emerging technologies,such as CCS and long‐duration storage are notselected due to economics. See Figure 68 for the totalsystem capacity, including other existing resources, through 2035.

Figure 67. Zero Emissions Scenario Cumulative New Build Capacity Figure 68. Zero Emissions Scenario Total Capacity
See Figure 69 for the annual generation by resource type through 2035 in the Zero Emissions Scenario.

Generation mix follows similar trends asseen in the Accelerated SB 100 Scenario in the near term. In 2035 when the zero‐emission limit is applied, no gas generation is allowed and all generation comes from renewable and carbon‐free resources, and zero‐emission market purchases. The reason that the zero‐ Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   103
carbon percentage exceeds 100% in 2035 is because it is calculated based on the accounting framework of SB 100, which is different from total system generation.

Figure 69. Zero Emissions Scenario Annual Generation
Note: RPS and Zero Carbon percentages are based on retail sales and based on the accounting framework of annual targets in SB 100
Figure 70 details the annual energy balance of loads and resources.

Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   104
Figure 70. Zero Emissions Scenario Annual Energy Balance of Loads and Resources Technology 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 6,436 7,037 7,492 7,964 8,428 8,953 9,210 9,387 9,559 5,983 DVR Gas - CC 1,160 1,196 1,141 1,027 1,007 1,006 1,027 1,067 891 - Gianera 1 Gas - CT 10 10 6 2 5 5 - - - 10
Gianera 2 Gas - CT 10 10 4 3 5 5 - - - 10
Alameda CT 1 Gas - CT - - - - - - - - - -
Alameda CT 2 Gas - CT - - - - - - - - - -
Lodi CT Gas - CT - - - - - - - - - -
LEC Gas - CC - - - - - - - - - 273
LEC Hydrogen 45 Blend Hydrogen Blend - 242 240 198 67 113 - - - - Collierville Large Hydro 158 158 158 158 158 158 158 158 158 158 BESS 50MW 200MWh Li-ion Battery (4-hr) (7) (6) (7) (7) (11) (11) (14) (13) (13) (15) Black Butte Small Hydro 8 8 8 8 8 8 8 8 8 8
Stony Gorge Small Hydro 7 7 7 7 7 7 7 7 7 6
Grizzly Hydro Small Hydro 43 43 43 43 43 43 43 43 43 43 Big Horn 1 Wind - - - - - - - - - 209
Big Horn 2 Wind 40 42 37 37 42 36 35 37 28 41
Geo Plant 1 Unit 1 Geothermal 105 105 105 105 105 105 105 105 105 105 Geo Plant 1 Unit 2 Geothermal 105 105 105 105 105 105 105 105 105 105 Geo Plant 2 Unit 4 Geothermal 140 141 140 140 140 140 141 140 140 140 Spicer Small Hydro 5 5 5 5 5 5 5 5 5 5
2,028 2,063 1,951 1,696 1,732 2,174 1,612 1,621 1,486 584 Tri-Dam Donnells Large Hydro 243 243 243 243 243 243 243 243 243 243 WAPA Base Resource Large Hydro 250 250 250 250 250 250 250 250 250 250 South Feather - Forbstown Large Hydro 60 59 57 59 60 58 59 59 57 59 South Feather - Woodleaf Large Hydro 100 99 98 97 99 100 98 95 94 99 Ameresco Forward Biogas 37 37 37 37 37 36 36 6 - 37
Ameresco Vasco Biogas 38 38 38 37 37 37 37 6 - 38
G2 Landfill Biogas - - - - - - - - - -
Tri-Dam Beardsley Small Hydro 44 45 45 44 45 44 44 43 43 43 Tri-Dam Sand Bar Small Hydro 74 73 75 73 75 74 73 70 70 71 Tri-Dam Tulloch Small Hydro 109 108 108 108 110 110 108 106 106 111 Friant 1 Small Hydro 67 66 66 65 66 66 66 65 65 66
Friant 2 (Quinten) Small Hydro 39 39 39 39 40 39 39 38 38 39 Rio Bravo (Index+) Small Hydro 15 14 14 14 15 14 13 15 14 15 Camp Far West Hydro (Index+) Small Hydro 26 24 26 25 25 25 26 25 26 26 South Feather - Kelly Ridge Small Hydro 27 27 28 27 27 27 27 27 27 26 South Feather - Sly Creek Small Hydro 14 14 14 14 14 14 14 14 1 13 4 Central 40 Solar Solar 113 110 111 113 113 106 108 110 108 113 Rosamond Solar Solar 63 61 62 63 62 59 60 62 59 62
Aquamarine Westside (Index+) Solar - - - - - - - - - -
Manzana Wind Wind 125 116 119 128 126 123 - - - 132
Cimmaron Wind Wind 786 742 783 887 821 854 783 794 752 930 Calpine Geo Geothermal 613 615 613 613 613 615 613 613 613 307 Sand Hill A Wind 28 29 28 28 29 30 27 27 29 30
Sand Hill B Wind 38 39 38 38 39 40 36 37 40 41
Rooney Ranch Wind 41 43 41 41 42 43 39 40 43 44
2,794 2,949 2,891 2,931 3,042 2,987 3,006 2,799 2,745 2,691 Hydrogen_Aero_CT_2035 Hydrogen - - - - - - - - 25 -
Li_Battery_4hr Li-ion Battery (4-hr) (9) (9) (11) (12) (17) (17) (20) (19) (18) (15) DVR Hydrogen Hydrogen - - - - - - - - 856 -
Alameda CT 1 Hydrogen Hydrogen - - - - - - - - - -
Alameda CT 2 Hydrogen Hydrogen - - - - - - - - - 5
Lodi CT Hydrogen Hydrogen - - - - - - - - - 5
LEC Hydrogen 100 Blend Hydrogen - - - - - 38 14 75 158 - Central_California_Wind Wind - - 256 378 378 541 542 550 563 - Geothermal Geothermal - - 466 465 1,055 1,413 1,977 2,432 2,802 3,000 New_Mexico_Wind Out-of-state Wind 509 489 515 599 612 588 564 566 655 583 Southern_California_Solar Solar 441 425 437 441 449 425 439 442 423 437 Wyoming_Wind Out-of-state Wind - 328 354 615 683 674 640 662 695 938 Gianera 1 RNG Biogas - - - - - - - - 10 -
Gianera 2 RNG Biogas - - - - - - - - - 8
1,250 1,750 2,360 3,152 3,485 937 4,165 4,637 5,201 6,558 532 685 625 472 646 617 614 424 204 379
(322) (352) (375) (399) (422) (448) (461) (470) (478) (300) 209 333 250 79 224 169 153 (46) 73 (274)
Net System Energy (GWh) 6,436 7,037 7,492 7,964 8,428 5,983 8,953 9,210 9,387 9,559 New Resources (NonRPS Eligible)
New Resources
(RPS Eligible)
Total New Resource Additions (GWh)
Market Purchases and Sales (GWh)
Market Purchases (GWh)
Market Sales (GWh)
Net Market Purchases (GWh)
Long-term Contracts
(RPS Eligible)
Total Long-term Contracts (GWh)
New Resource Additions - Generation (GWh)
SVP Owned Units
(Non-RPS Eligible)
SVP Owned Units
(RPS Eligible)
Total SVP Owned Units (GWh)
Long-Term Contracts - Generation (GWh)
Long-term Contracts
(Non-RPS Eligible)
Annual Energy Balance of Loads and Resources
Silicon Valley Power
Description
System Annual Energy Demand (GWh)
SVP Owned Units - Generation (GWh)
Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   105
Figure 71 shows the system reliability modeling results through 2035 in the Zero Emissions Scenario.

Resource capacity contribution is similar to the Accelerated SB 100 Scenario before 2035. In 2035, more clean resources are added to the system due to the stringent emission target and surpass the marginal reliability need, meaning the marginal reliability requirement is not the primary driver of resource builds by 2035.

Figure 71. Zero Emissions Scenario Marginal Reliability Need and Marginal Effective Capacity Figure 72 details the annual marginal reliability need and resource capacity.

Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   106
Figure 72. Zero Emissions Scenario Marginal Reliability Need and Resource Capacity Accreditation
Technology 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 906 987 1,056 845 1,124 1,186 1,251 1,287 1,315 1,341
System Coincident Peak (Coincident with 2022 IEPR CAISO Gross Peak) 790 843 858 952 1,010 1,085 1,164 1,163 1,144 1,210 PCAP PRM (%) 14% 14% 14% 14% 14% 14% 14% 14% 14% 14%
System Total Reliability Need (MW) 961 979 1,085 900 1,152 1,237 1,326 1,326 1,304 1,380 CAISO Portfolio Effects (MW) 107 116 203 243 300 333 370 334 432 76 853 863 882 909 937 993 956 970 947 825
DVR Gas - CC 129 129 127 126 128 129 131 133 - 130
Gianera 1 Gas - CT 20 20 20 20 20 20 20 21 - 21
Gianera 2 Gas - CT 20 20 20 20 20 20 20 21 - 21
Alameda CT 1 Gas - CT 8 8 8 - - - - - - 8
Alameda CT 2 Gas - CT 8 8 8 8 - - - - - -
Lodi CT Gas - CT 8 8 8 8 8 - - - - 8
LEC Gas - CC - - - - - - - - - 68
LEC Hydrogen 45 Blend Hydrogen Blend - 68 68 67 66 67 - - - - Collierville Large Hydro 49 46 45 44 43 42 41 40 39 51
BESS 50MW 200MWh Li-ion Battery (4-hr) 46 42 39 38 37 34 30 27 23 20 Black Butte Small Hydro 2 2 2 2 2 2 2 2 2 2
Stony Gorge Small Hydro 2 2 2 2 2 2 2 2 2 2
Grizzly Hydro Small Hydro 7 6 6 6 6 6 6 6 5 7
Big Horn 1 Wind - - 23 - - - - - - -
Big Horn 2Wind4 4 3 3 3 3 3 3 3 4
Geo Plant 1 Unit 1 Geothermal 11 11 11 11 11 11 11 11 11 11 Geo Plant 1 Unit 2 Geothermal 11 11 11 11 11 11 11 11 11 11 Geo Plant 2 Unit 4 Geothermal 15 15 15 15 15 15 15 15 15 14 Spicer Small Hydro 1 1 1 1 1 1 1 1 1 1
406 399 392 370 369 292 290 289 110 436
Tri-Dam Donnells Large Hydro 38 36 35 35 34 33 32 32 31 40 WAPA Base Resource Large Hydro 67 63 62 61 59 58 57 55 54 71 South Feather - Forbstown Large Hydro 13 12 12 12 13 1 11 11 11 10 1 South Feather - Woodleaf Large Hydro 20 19 19 19 18 18 17 17 17 22 Ameresco Forward Biogas 3 3 3 3 3 3 3 - - 3
Ameresco Vasco Biogas 3 3 3 3 3 3 4 - - 3
G2 Landfill Biogas - - - - - - - - - -
Tri-Dam Beardsley Small Hydro 4 4 4 4 4 4 4 4 4 5
Tri-Dam Sand Bar Small Hydro 6 6 6 6 5 5 5 5 5 7
Tri-Dam Tulloch Small Hydro 10 9 9 9 9 9 8 8 8 10
Friant 1 Small Hydro 10 9 9 9 8 8 8 8 8 10
Friant 2 (Quinten) Small Hydro - - - - - - - - - -
Rio Bravo (Index+) Small Hydro 5 5 5 5 5 5 5 4 4 6
Camp Far West Hydro (Index+) Small Hydro 3 2 2 2 2 2 2 2 2 3 South Feather - Kelly Ridge Small Hydro 3 3 2 2 2 2 2 2 2 3 South Feather - Sly Creek Small Hydro 3 3 3 3 3 3 3 3 3 3 Central 40 Solar Solar 4 4 3 2 2 2 2 3 3 4
Rosamond Solar Solar 2 2 2 1 1 1 1 1 1 2
Aquamarine Westside (Index+) Solar - - - - - - - - - -
Manzana Wind Wind 6 4 4 4 4 3 - - - 8
Cimmaron Wind Wind - - - - - - - - - -
Calpine Geo Geothermal 64 65 65 64 65 65 66 66 67 31
Sand Hill A Wind 3 2 2 2 2 2 2 1 1 4
Sand Hill B Wind 4 3 3 3 3 2 2 2 2 5
Rooney Ranch Wind 5 3 3 3 3 3 2 2 2 6
277 262 257 252 248 244 237 226 222 260
Hydrogen_Aero_CT_2035 Hydrogen - - - - - - - - 24 -
Li_Battery_4hr Li-ion Battery (4-hr) 73 86 79 77 76 69 62 55 48 41 DVR Hydrogen Hydrogen - - - - - - - - 135 -
Alameda CT 1 Hydrogen Hydrogen - - - - 8 8 8 8 8 8
Alameda CT 2 Hydrogen Hydrogen - - - - 8 8 8 8 8 8
Lodi CT Hydrogen Hydrogen - - - - - - 8 8 8 8
LEC Hydrogen 100 Blend Hydrogen - - - - - 68 69 70 71 - Central_California_Wind Wind - - - 8 10 9 12 10 9 8
Geothermal Geothermal - 49 49 111 150 211 263 304 331 - New_Mexico_Wind Out-of-state Wind 40 42 44 40 30 32 34 35 37 39 Southern_California_Solar Solar 15 14 12 9 9 9 9 9 10 16 Wyoming_Wind Out-of-state Wind - 28 29 47 35 37 39 41 43 60 Gianera 1 RNG Biogas - - - - - - - - 21 -
Gianera 2 RNG Biogas - - - - - - - - - 21
171 215 233 287 321 459 507 545 784 129
853 876 882 909 939 995 825 1,035 1,059 1,117
New Resources (NonRPS Eligible)
New Resources
(RPS Eligible)
Total New Resource Additions (MW)
Total System Marginal ELCC Capacity (MW)
Long-term Contracts
(Non-RPS Eligible)
Long-term Contracts
(RPS Eligible)
Total Long-term Contracts (MW)
New Resource Additions - Marginal Effective Load Carrying Capability, ELCC (MW) SVP Owned Units - Marginal Effective Load Carrying Capability, ELCC (MW) SVP Owned Units
(Non-RPS Eligible)
SVP Owned Units
(RPS Eligible)
Total SVP Owned Units (MW)
Long-Term Contracts - Marginal Effective Load Carrying Capability, ELCC (MW) Marginal Reliability Need and Resource Capacity Accreditation Silicon Valley Power
Description
System Non-Coincident Peak Demand (MW)
System Marginal Reliability Need (MW)
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8.4. Scenario Comparison
In 2030, the three scenarios have similar resource additions. At least 120 MW geothermal, 400 MW wind, 150 MW solar, and 100 MW battery are selected across the scenarios, indicating that these resources are fairly robust and likely low‐regret decisions for SVP in the near term, given the assumptions in this study.

Figure 73. Scenario Comparison – 2030 Cumulative New Build Capacity While the three scenarios have similar resource additions in the near‐term, they begin to diverge towards the end of the planning horizon as more aggressive clean energy targets are applied in Scenario 2:

Accelerated SB 100 (Accelerated SB 100 Scenario) and Scenario 3: Zero Emissions with Emerging Technology (Zero Emissions Scenario). Figure 74 compares the cumulative resource additions between the scenarios by 2035. The resource capacitiesin the Zero Emissions Scenario include the assumed retrofit of some existing SVP natural gas resources (DVR, Gianera, and LEC) to zero‐emission fuels.

Compared to Scenario 1: Base SB 100 (Base Scenario), the Accelerated SB 100 Scenario adds about 40 MW more geothermal, 150 MW more wind, and 30 MW more solar capacitiesto achieve the accelerated 100% carbon free of retail sales by 2035 based on SB 100’s annual accounting framework.

Compared to the Base Scenario, the Zero Emissions Scenario assumes 300 MW of existing gas resources are converted to zero‐emission fuel by 2035 and adds about 30 MW more hydrogen and 50 MW more geothermal resources to the portfolio. While solar and battery storage capacities are similar, wind capacity is 60 MW less than the Base Scenario due to the availability of emerging technologies and additional geothermal capacity selected. Clean firm resources, such as hydrogen and geothermal considered in this IRP, are favored in this scenario as it is difficult to meet SVP’s load profile with no emissions in every hour without firm and dispatchable resource options. The critical role of “clean firm” Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   108
resources in deep‐decarbonized and zero‐emission systems has been highlighted and discussed in the industry.51
Figure 74. Scenario Comparison – 2035 Cumulative New Build Capacity Figure 75 shows a comparison of total capacity between the three scenarios in 2035. The total capacity of the Zero Emissions Scenario issimilar to the Base Scenario and lower than the Accelerated SB 100 Scenario because it includes the zero‐emission fuel conversion of some of the existing gas resources and other emerging technologies. However, there are uncertainties in these assumptions. If emerging technologies and zero‐emission fuels are not available to SVP by 2035, SVP would need to procure higher amounts of existing mature technologies, such as solar, wind, and battery storage resources to achieve zero emission in every hour. The total nameplate capacity of those resources is likely higher than the system load and the three scenarios explored here. Because they have low and marginally decreasing reliability value, more capacity would be needed to cover the most critical hours, even though there might be high curtailment in other normal and/or low load hours. Emerging technology options, such as new hydrogen plants and retrofit of existing gas plants to hydrogen or biogas, offer the “clean firm” attributes and significantly reduces the potential for “overbuilding” existing mature technologies. Thus, reaching a zero‐ emissions SVP system atreasonable costs by 2035 requiresreliance on “clean firm” emerging technologies that are not available commercially at scale today.
51 Burdick et al, 2022. “Lighting a Reliable Path to 100% Clean Electricity. Evolving Resource Adequacy Practices for a Decarbonizing Grid.” IEEE Power & Energy Magazine. July/August 2022 NREL. “LA100 Report.” 2021. https://maps.nrel.gov/la100/la100‐study/report E3 and EFI. “Net‐Zero New England: Ensuring Electric Reliability in a Low‐Carbon Future.” 2020. https://www.ethree.com/wp‐ content/uploads/2020/11/E3‐EFI_Report‐New‐England‐Reliability‐Under‐Deep‐Decarbonization_Full‐ Report_November_2020.pdf
E3. “Resource Adequacy in the Pacific Northwest.” 2019. https://www.ethree.com/wp‐ content/uploads/2019/03/E3_Resource_Adequacy_in_the_Pacific‐Northwest_March_2019.pdf Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   109
Figure 75. Scenario Comparison – 2035 Total Capacity
Figure 76 shows the comparison of annual generation between the three scenarios in 2035. Gas generation reduces from Base to Accelerated SB 100 Scenario as the clean energy target increases and becomes zero in the Zero Emissions Scenario. Market purchases also reduce, and the annual net market transaction becomes net sales to market in the latter two scenarios as more energy needs to come from specified renewable and carbon‐free resources, and market purchases can only occur in periods when the market is also “clean” (i.e., the emission factor is zero) in the most stringent scenario.

Figure 76. Scenario Comparison – 2035 Annual Generation Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   110
Figure 77 shows the comparison of annual CO2 emissions between the three scenarios in 2035. This includes emissions from SVP’s resources and market purchases. It also includes emission offset credits from market sales when applicable in the Base and Accelerated SB 100 Scenarios (see Section 6.4 for the detailed emission accounting methodology). The 2035 annual emissions are approximately 380,000 metric tons, 85,000 metric tons in the Accelerated SB 100 Scenario, and zero in the Zero Emissions Scenario. System emission reduces following the generation mix trends discussed above.

Figure 77. Scenario Comparison – 2035 Annual CO2 Emission Note: Annual CO2 emission includes emission from SVP’s resources and market purchases. In the Base and Accelerated SB 100 Scenarios, it also includes emission offset credits from market sales when applicable.

See Figure 78 for the comparison of annual modeled cost between the three scenarios in 2035. This only represents the cost components modeled and does not represent SVP’s total revenue requirement.

Modeled cost includes the operational cost (e.g., variable O&M, fuel costs) of existing and planned capacity, and the capital cost and operational cost of new build capacity. Capital and fixed costs (including PPA cost) of existing and planned capacity are not included. Transmission and distribution costs are also not included.

Compared to the annual modeled cost in the Base Scenario, which reaches $250 million (2022 $; TAC costs and non‐modeled system costs are excluded) in 2035, the annual modeled cost increases by about $25 million (2022 $) in the Accelerated SB 100 Scenario and increases by $55 million (2022 $) in the Zero Emissions Scenario. However, it is important to note that there are large uncertainties in the availability and cost of emerging technologies and zero‐emission fuels by 2035. As discussed above, without the clean firm emerging technologies modeled in this study, achieving zero emissions with only commercially available resources will likely require significant “overbuilding” of those resources to maintain reliability and the system cost can be much higher. Furthermore, the cost of converting some of the existing gas resources to zero‐emission fuels is potentially underestimated due to uncertainties in conversion Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   111
technologies and limited data at the time of this IRP study. Resource cost and availability uncertainties can have large impacts to the resulting portfolio and system cost, and they should continue to be monitored by SVP in future IRPs.

Figure 78. Scenario Comparison – 2035 Annual Cost Relative to Base Scenario (2022 $MM) Note: Annual modeled cost includes the operational cost of existing/planned capacity and the capital cost and operational cost of new build capacity. Capital and fixed costs (incl. PPA cost) of existing/planned capacity are not included. Transmission and distribution costs are not included.

8.5. Sensitivity: Geothermal Limitations and Hydrogen Challenges The Geothermal Limitations and Hydrogen Challenges Sensitivity (Hydrogen Sensitivity) represents an additional modification to Scenario 3: Zero Emissions with Emerging Technology (Zero Emissions Scenario), designed to explore uncertainty over future hydrogen prices and resource availability. Like the Zero Emissions Scenario, this sensitivity includes the most stringent clean energy target modeled in this IRP, limiting emission to zero in every hour in 2035.

The cost of hydrogen retrofits and hydrogen fuel prices are uncertain in a future scenario with deep decarbonization. In this sensitivity, hydrogen costs have been increased relative to the Zero Emissions Scenario to reflect an upper bound to this uncertainty. Hydrogen retrofits costs for SVP’s existing gas fleet have been doubled, and fuel prices have been increased by making more conservative assumptions for electrolyzer technology, process electricity costs, and pipeline capacity factor. See Figure 52 and Appendix C for details on hydrogen price forecast.

Finally, this sensitivity explores scarcity of conventional clean firm resources by limiting SVP’s geothermal resource potential to 50 MW, first available in 2028.

Figure 74 shows the cumulative resource additions through 2035 in the Hydrogen Sensitivity. The figure includes the above existing resources’ assumed transitions to zero‐emission fuels. By 2035, the total Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   112
resource additions include 163 MW of CCS, 255 MW hydrogen (all coming from assumed transitions SVP’s existing thermal fleet), 50 MW geothermal, 50 MW biogas (assumed transition of Gianera), 1,262 MW wind, 62 MW offshore wind, 905 MW solar, and 276 MW battery storage. Other emerging technologies, such as nuclear and long‐duration storage, are not selected due to economics. See Figure 80 for the total system capacity, including other existing resources, through 2035.

Figure 79. Hydrogen Sensitivity Cumulative New Build Capacity Figure 80. Hydrogen Sensitivity Total Capacity
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See Figure 81 for the annual generation by resource type through 2035 in the Hydrogen Sensitivity. In 2035, when the zero‐emission limit is applied, no gas generation is allowed and all generation comes from renewable and carbon‐free resources, and zero‐emission market purchases. The reason that the zero‐ carbon percentage exceeds 100% in 2035 is because it is calculated based on the accounting framework of SB 100, which is different from total system generation.

Figure 81. Hydrogen Sensitivity Annual Generation
Note: RPS and Zero Carbon percentages are based on retail sales and based on the accounting framework of annual targets in SB 100
Figure 82 shows the system reliability modeling results through 2035 in the Hydrogen Sensitivity. Unlike previous scenarios, the reliability constraint binds in 2033‐34 due to the reduced geothermal resource potential before emerging technologies are available for selection. In 2035, more clean resources are added to the system due to the stringent emission target and surpass the marginal reliability need, meaning the marginal reliability requirement is not the primary driver of resource builds in 2035.

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Figure 82. Hydrogen Sensitivity Marginal Reliability Need and Marginal Effective Capacity

8.6. Challenges Ahead to Meet IRP Goals
Through studying Scenario 1: Base SB 100 (Base Scenario) that meets the current state policies, and two additional scenarios with more aggressive clean energy requirements in this IRP, multiple challenges are identified as SVP continues to provide affordable, clean, and reliable power to its growing customer load.  SVP’s load, primarily data center load, is expected to grow substantially throughout the planning horizon. The forecasted annual load in 2035 almost doubles the current system load, and significant resource additions are needed to meet this growing load. Also, unlike other utilities, SVP’s current and forecasted load is dominated by industrial (datacenter) load, which has a high load factor (or average load divided by peak load) of 80%, meaning that the system demand is relatively constant and there is less ability to shape loads to take advantage of certain resource production,such aslow‐costsolar. Therefore, SVP’sfuture portfolio requires both clean resources and firm resources that can ensure there is enough energy to meet system load in all hours.  SVP will need clean firm resources, such as geothermal, to meet future needs in a deep decarbonized system. SVP faces a common challenge of deeply decarbonized systems, which is the ability to provide power reliably without firm dispatchable (emitting) thermal plants. Clean firm resources not only provide clean energy, but also firm capacity to help ensure system reliability. The clean, firm, and baseload characteristics of geothermal align well with SVP’s forecasted load growth and load shape and could provide a key clean firm option.

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 Competition for limited resources in California can add difficulties for SVP to procure some of cost‐effective resources for its system. For example, only a limited amount, about 3,400 MW, of geothermal may be available to California. Furthermore, the CPUC Mid‐Term Reliability order requires CPUC‐jurisdictional LSEs to procure approximately 1,000 MW long lead‐time clean firm resources by 2028, and geothermal is one of the best available candidates to meet that order. An assumption of this IRP is that SVP may not be able to procure that 1,000 MW tranche. SVP would then be limited to a maximum of about 350 MW, which is approximately 15% of the remaining potential. The three scenarios in this IRP build to, or slightly below that limit. However, with the recent IRA including additional incentives for geothermal resources, and with all LSEs in California transitioning to a cleaner portfolio, there is a growing need for clean and firm resources, further driving competition for limited resources, such as geothermal, and adding challenges (and potentially costs) to cost‐effective resource procurement.  SVP faces uncertainties in project delivery timelines. To keep pace with near‐term load growth to 2030 and longer‐term load growth and policy objectives, SVP will need to bring significant quantities of new resources online over the nextseveral years. As development for new resources in California increases to unprecedented rates, SVP may face challenges including, but not limited to supply chain delays, labor shortage, as well as permitting and lengthy interconnection queue processes. To build and begin utilizing new resources, the cost and schedule uncertainty of a complex, multi‐step, multi‐year interconnection process can significantly complicate other parts of the development process, including financing and project costs.  There are uncertainties in long‐term resource cost forecasts. This IRP uses the long‐term resource cost forecastfrom the industry standard public data source, the NREL Annual Technology Baseline (ATB). However, recent market trends have shown that international trade policies and supply chain issues can significantly impact resource costs during procurement. Furthermore, market competition and developer profit markup are difficult to forecast and model but do influence resource costs. While many cost uncertainties are not explicitly studied in this IRP, they can impact the resulting portfolio choices and system costs. SVP should continue to monitor resource costs in future IRPs and resource procurement activities.  Achieving zero emission in every hour will likely require a combination of commercially available resources and new emerging technologiesto be cost‐effective and affordable. To meet the hourly zero‐emission target, all generation needs come from renewable, carbon‐free resources, and/or market purchases (also when market emissions are zero) in every hour. If emerging technologies and emerging zero‐emission fuels are not available, SVP would need to add much higher amounts of existing commercially available technologies, such as solar, wind, and battery storage resources. The total nameplate capacity of those resources is likely higher than the system load and the three scenarios presented here. Because they have low and Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   116
marginally decreasing reliability value, more capacity is needed to cover the most critical hours, even though there might be high curtailment occurring in other normal and/or low load hours.

The emerging technologies, such as building new hydrogen plants and converting existing gas plants to burn on hydrogen or biogas, modeled in this IRP offer both clean and “firm capacity” attributes, and reduces the potential for “overbuilding” existing mature technologies.  There are large uncertainties and risks in emerging technologies. The emerging technologies modeled in this IRP are developed based on various assumptions and limited data. Many of the emerging technologies are still in their research and development and/or piloting phases, and it is difficult to predict when they will be commercially available at scale. Additionally, some emerging technologies, such as green hydrogen, require significant infrastructure development, such as electrolyzers, renewables for electrolyzers, pipelines, and storage. The costs and infrastructure required to support emerging technologies are uncertain and can impact the resulting portfolio feasibility and cost. The development of emerging technologies should continue to be monitored and studied by SVP in future IRPs and resource procurement.  SVP’stransmission capabilities with CAISO can have an impact on how much emission reduction SVP can achieve. DVR and Gianera are the only two resources, both natural gas plants, located within SVP’s local zone. When trying to meet more aggressive clean energy goals and reduce gas generation, the local resources’ roles and SVP’s transmission capabilities with CAISO become important. If the local resources cannot be dispatched to meet SVP’s load, all system load must be met with energy delivered via the transmission line from CAISO. However, the existing and planned transmission capacity may not always be sufficient to cover SVP’s forecasted peak load.

In this IRP, it is assumed that local resources would be able to run on emerging zero‐emission fuel and can be dispatched in Scenario 3: Zero Emissions with Emerging Technology, but SVP should continue to study system transmission capabilities and the clean transition of local resources in future IRPs.

8.7. Potential Impacts on Retail Rates
SVP is obligated to serve its customers at just and reasonable rates and to minimize impactsto ratepayers.

Notably for SVP, lower rates have been an economic driver for robust development within Santa Clara, and continuing this long‐standing focus on providing affordable and reliable services to customers is a goal of this IRP. This section explores the potential impact that the three scenarios explored in this work may have on retail rates through the planning horizon.

Figure 83 showsthe estimated retail rate impacts of the scenariosfrom 2024 to 2035. Rates are calculated as the annual cost and annual retail demand ($/kWh). These estimates are based on two components 1) non‐modeled costs, which are SVP baseline system rates, and 2) the incremental modeled scenario costs and TAC costs. The SVP baseline system rates are assumed to escalate at 3% real (5% nominal) per year, Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   117
which SVP characterizes as the baseline revenue requirements for the system. The incremental scenario costs shown represent the additional cost to implement each scenario in order of least to most stringent clean energy requirements. Of note here is the impact of the significant impact of TAC, a charge from CAISO for energy delivered into SVP service area, on the final rates, which is a charge that is not overseen by SVP.

Scenario 1: Base SB 100 (Base Scenario) rates reach approximately $0.16/kWh in 2030 and approximately $0.185/kWh by 2035. Additional rate impacts from Scenario 2: Accelerated SB 100 begin later in the horizon, with an incremental cost of approximately $0.002/kWh by 2035 (or an estimated $0.187/kWh).

Finally, Scenario 3: Zero Emissions with Emerging Technology (Zero Emissions Scenario) results in an incremental cost to the Base Scenario of approximately $0.005/kWh by 2035 reaching approximately $0.19/kWh by 2035.

Although the cost impacts are less apparent when spread across the annual load here, the 2035 annual costs of these scenarios relative to Base Scenario are 2022 $25 million and 2022 $55 million, in the Accelerated SB 100 and Zero Emissions Scenarios, respectively (see Figure 78).

Figure 83. Estimated Retail Rates Impacts
The uncertainties related to emerging technology availability and costs, as discussed in the previous section, of course, carry through to these estimated rate impacts. The relatively slight rate impacts of reaching the Zero Emissions Scenario ride on the assumptions that existing SVP resources can be retrofit to clean energy fuels at minimal to no capital costs by 2035 with low‐cost (PTC‐ eligible) hydrogen fuel availability. The sensitivity case that tested potential geothermal availability limitations and high hydrogen costs results in an incremental cost to the Base Scenario of approximately $0.012/kWh by 2035 reaching approximately $0.197/kWh by 2035.

8.8. Consideration of Localized Air Pollutants and Disadvantaged Communities Santa Clara’s defined Disadvantaged Community is comprised of Industrial and Commercial customers with few residential and even fewer income‐qualified FRAP (Federal Rate Assistance Program customers) residential customers residing within the borders as shown in Figure 84. SVP’s disadvantaged community Results and Discussion2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   118
(DAC) borders Highway 101 and the San Jose Airport and is comprised of 24/7 manufacturing, SVP’s DVR power plant, data centers, high tech companies and small industrial customers. Santa Clara haszoned this area of the city for heavy industrial and commercial and has kept housing at a minimum with few exceptions.

Santa Clara is only 18.4 square miles and land is at a premium, and in most cases, utilized to maximum densities. In working with the City of Santa Clara as it updates its General Plan, there is an opportunity for SVP to encourage maximum infill building potential with whole building electrification and maximize potential of DERs. There is no land available to build large‐scale PV projects (greater than 10 MW) within the city limits, but there is ample opportunity throughout California, keeping with SVP’s position of having a diversified portfolio (both geographically and resource type). Adding renewable generation to SVP’s portfolio is beneficial to the disadvantaged community as well as to SVP’s service area.

SVP offers multiple customer programs and rebates to income‐qualified customers, as outlined below.

Specifically for energy efficiency, one of the many goals of the programs is to assist income‐qualified residents in paying their electric bills and installing energy efficient appliances to lower energy costs. The following programs are offered by SVP to specifically support income‐qualified and disadvantaged communities:
 Financial Rate Assistance Program (FRAP)
 Multifamily Residential and Commercial EV Charging Station Incentive Program (Equity+ Funding Lane)
 Free EV Charging Technical Assistance for Multifamily Housing & Small Businesses  E‐Bike Rebate (Increased incentives for FRAP customers)  Heat Pump Water Heater Rebate (Increased incentives for FRAP and LIHEAP customers)  Income‐Qualified Pre‐Owned Electric Vehicle Rebate
 Income‐Qualified Solar Grant
 Smart Electric Panel (Increased incentives for FRAP and LIHEAP customers)  Battery Storage Systems Rebate (Increased incentives for FRAP and LIHEAP customers)  Medical Rate Assistance Program
 Trade School Scholarships for income‐qualified customers  Increased rebates on electric yard care equipment and room air cleaners for income‐qualified customers through the online SVP Marketplace
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Figure 84. Disadvantaged Communities within SVP’s Service Territory Conclusions2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   120

9.Conclusions
SVP’s 2023 IRP identified three least‐cost optimal resource portfolios, all of which meet or exceed SVP's clean energy, emissions reductions, and reliability requirements. In all portfolios, the power supply mix continues SVP’s transition away from carbon‐based generation with significant, new clean energy resource additions to meet increasing state policy goals and SVP’s growing load. The portfolios studied represent increasingly progressive clean energy goals. Scenario 1: Base SB 100 (Base Scenario) meets the SB 100 target of 60% renewable energy in 2030 and 90% renewable and zero‐carbon energy by 2035, relying only on mature clean energy technologies. Scenario 2: Accelerated SB 100 explores additional procurement required to meet an acceleration of the long‐term SB 100 targets for 100% carbon free electricity from 2045 to 2035 and relies only on mature renewable technology options. Finally, Scenario 3: Zero Emissions with Emerging Technology (Zero Emissions Scenario) limits carbon emissions in all hours of the year, beginning in 2035, and explores the use of emerging clean energy technologies.

All the resulting portfolios represent diverse resource mixes of clean firm capacity, scalable clean energy, and balancing resources. Portfolio capacity additionsinclude a mix ofsolar, in‐state and out‐of‐state wind, energy storage, and geothermal capacity. The added firm geothermal and balancing storage resources, in addition to SVP’s existing firm capacity, complement the intermittent nature of the high level of variable wind and solar resources added, ensuring SVP has sufficient capacity to meet its share of CAISO reliability needs. In the near term, through 2030, all resource portfolios present a common trend of at least 400 MW wind, 150 MW solar, 100 MW battery energy storage and 120 MW geothermal resource additionsto meet increasing load as well as reliability and clean energy targets. This presents a robust, fairly low‐regrets near‐term planning pathway for the level of SVP clean energy resource additions.

The scenarios begin to diverge after 2030 as potential clean energy and emissions requirements and emerging technologies are assumed to become increasingly available. By 2035 the Zero Emissions Scenario diverges with the assumed availability of hydrogen and biofuel clean‐firm resources, enabling SVP to retrofit existing fossil‐fuel resources and add additional hydrogen combustion capacity.

Sensitivities on the availability of geothermal (clean firm) and hydrogen costs (retrofit capital costs and hydrogen fuel prices) show the increased costs that could occur due to competition over limited geothermal potential and a less optimistic view of hydrogen as an electricity generation fuel. Uncertainty for these “clean firm” resources needed to help SVP and the state achieve a zero‐emissions grid can be addressed by furtherstudy in SVP’ssubsequent IRPs, when the California electricity market will have more clarity on the viability and cost parameters of new emerging technologies. However, with large near‐term forecasted load growth, this IRP provides SVP with a clear pathway for near‐term procurement to meet its needs over the next 5‐10 years.

It is noted that while this IRP provides an outline for future resource additions, SVP’s actual future resource additions will be determined by results of competitive solicitations for resources and these may differ based on changesin forecasted loads, economic conditions, technology advances,specific bid‐based generation resource prices, and evolving environmental and regulatory standards.

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Appendix A. SVP Community Survey Summary

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Appendix B. Energy Demand
A.1. Energy Use and Demand
E3 leveraged a range of sources to develop a Reference Scenario and two sensitivities of annual peak load and hourly energy demand forecasts for SVP:
 Reference: a business‐as‐usual forecast of energy demand in SVP territory using the utility’s baseline forecast of energy demand with additional energy efficiency and electrification projections from the Planning Forecast of the CEC 2022 IEPR52  High Electrification: utilizes the same baseline forecast of energy demand as the Reference scenario, but layers in less aggressive energy efficiency assumptions and more aggressive electrification assumptions from the 2022 IEPR
 IEPR Local Reliability: utilizes the same baseline forecast of energy demand as the Reference scenario, but uses energy efficiency and electrification projections from the Local Reliability Forecast of the 2022 IEPR
Figure 85. Total Annual Electricity Demand by Scenario (GWh) Scenario 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Reference 4,529 4,933 5,494 5,995 6,449 7,044 7,503 7,971 8,448 8,955 9,218 9,394 9,567 High Elec. 4,546 4,965 5,548 6,072 6,553 7,175 7,668 8,171 8,684 9,228 9,529 9,742 9,950 IEPR Local
Reliability 4,773 5,171 5,794 6,381 6,938 7,489 7,919 8,381 8,883 9,415 9,838 10,040 10,248 E3 used two sources for energy efficiency assumptions: the 10 Year Energy Goals provided by SVP and AAEE modeled by CEC for the 2022 IEPR.53 Different levels of AAEE were used for each:
 The Reference scenario used the “Scenario 3 (Mid)” AAEE assumptions from the 2022 IEPR for Residential and Commercial sector energy efficiency, aligning with the assumptions used in the 2022 IEPR Planning Forecast
 The High Electrification scenario used the “Scenario 1 (Very Low)” AAEE assumptions, the most conservative scenario for energy efficiency included in the 2022 IEPR  The IEPR Local Reliability scenario used the “Scenario 2 (Low)” AAEE assumptions, aligning with the assumptions used in the 2022 IEPR Local Reliability forecast 52 CEC, “CEC 2022 Integrated Energy Policy Report (IEPR).” 53 CEC, “2022 IEPR AAEE‐AAFS Annual Impacts.” Energy Demand2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   130
Figure 86 shows the combined impact of energy efficiency measures on annual electricity demand in each scenario.

Figure 86. Annual Energy Efficiency Impact on Electricity Demand by Scenario (GWh) Scenario 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Reference ‐62 ‐97 ‐136 ‐171 ‐204 ‐226 ‐248 ‐271 ‐294 ‐313 ‐333 ‐350 ‐365 High Elec. ‐45 ‐65 ‐83 ‐98 ‐110 ‐113 ‐116 ‐121 ‐126 ‐128 ‐132 ‐135 ‐138 IEPR Local
Reliability ‐52 ‐79 ‐104 ‐126 ‐146 ‐156 ‐166 ‐178 ‐189 ‐199 ‐209 ‐217 ‐224 Additional electricity demand modifiers for building electrification are layered into the baseline. For buildings, the electrification assumptions are based on the AAFS modeled by CEC for the 2022 IEPR in all scenarios. For the High Electrification and IEPR Local Reliability scenarios, E3 also included electrification assumptions based on the 2022 Electric Infrastructure Impactsfrom Proposed Zero NOx Standardsreport, where E3 analyzed the electricity demand implications of a zero NOx standard forspace and water heaters for the Bay Area Air Quality Management District.54
 The Reference scenario used the “Scenario 3 (Mid)” AAFS assumptions, aligning with the assumptions used in the 2022 IEPR Planning Forecast
 The High Electrification scenario also used the “Scenario 3 (Mid)” AAFS assumptions and layered in additional electrification of space and water heating based on a zero NOx standard beginning in 2027 for residential water heating and 2029 for residential space heating, commercial water heating, and commercial space heating
 The IEPR Local Reliability scenario used the “Scenario 4 (High)” AAFS assumptions and layered in the same additional electrification of space and water heating from a zero NOx standard as the High Electrification scenario
Figure 87 shows the combined impact of building electrification measures on annual electricity demand in each scenario.

Figure 87. Annual Building Electrification Impact on Electricity Demand by Scenario (GWh) Scenario 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Reference 13 21 29 36 43 51 59 67 74 81 88 94 99
High Elec. 13 21 29 36 47 57 73 89 105 121 136 151 165
IEPR Local
Reliability 14 22 31 39 50 61 78 95 111 128 144 159 173 For transportation electrification, the Reference scenario reflects the Base level of electrification from the 2022 IEPR, while the High Electrification and Local Reliability scenario both use the Additional Annual Transportation Electrification (AATE) assumptions modeled in the 2022 IEPR Planning Forecast. While the 54 E3, “Bay Area Air Quality Management District” (San Francisco, CA: Energy + Environmental Economics (E3), 2022), https://www.baaqmd.gov/~/media/dotgov/files/rules/reg‐9‐rule‐4‐nitrogen‐oxides‐from‐fan‐type‐residential‐central‐ furnaces/2021‐amendments/documents/20221220_sr_appd_rg09040906‐pdf.pdf?la=en.

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AAEE and AAFS assumptions for energy efficiency and building electrification for the 2022 IEPR are provided at the SVP territory level, the Base and AATE assumptions are provided at the PG&E planning area level.55 E3 downscaled the transportation loads to SVP territory through a two‐step process. First, loads were scaled to Santa Clara County based on the county’s share of light duty vehicle and medium‐ and‐heavy duty vehicles registrations for all counties in PG&E service territory using California DMV vehicle registration data.56 Next, transportation loads were scaled from Santa Clara County to SVP service territory using the City of Santa Clara’s share of total vehicle miles travelled for Santa Clara County as reported in the city and county’s respective GHG inventories.5758 Figure 88 shows the combined impact of transportation electrification measures on annual electricity demand in each scenario.

Figure 88. Annual Transportation Electrification Impact on Demand by Scenario (GWh) Scenario 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Reference 8 15 24 32 40 49 59 69 81 94 107 120 135
High Elec. 8 15 25 35 47 62 78 97 119 142 168 196 225
IEPR Local
Reliability 8 15 25 35 47 62 78 97 119 142 168 196 225
Finally, the IEPR Local Reliability included a demand modifier to align total annual electricity demands between the E3 bottom‐up constructed demand scenario with the published Local Reliability forecast from the 2022 IEPR.

The total annual electricity demand for each scenario is shown in Figure 89. 55 CEC, “2022 IEPR AAEE‐AAFS Annual Impacts”; CEC, “CED 2022 Hourly Forecast ‐ PGE ‐ Planning Scenario.” 56 CA DMV, “VEHICLES REGISTERED BY COUNTY,” California Department of Motor Vehicles, 2023, https://www.dmv.ca.gov/portal/dmv‐research‐reports/research‐development‐data‐dashboards/vehicles‐registered‐by‐ county/. 57 Country of Santa Clara, “2017 Community Wide Greenhouse Gas Inventory and Forecast” (Santa Clara, CA: County of Santa Clara, 2021),
https://sustainability.sccgov.org/sites/g/files/exjcpb976/files/documents/SCC%20GHG%20Inventory%20and%20Forecast%2 0Report_6‐29‐21_0.pdf. 58 City of Santa Clara, “Climate Action Plan: 2018 Annual Report” (Santa Clara, CA: City of Santa Clara, 2018), https://www.santaclaraca.gov/home/showpublisheddocument/62433/636809212556470000.

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Figure 89. Total Annual Electricity Demand by Scenario
Hourly Energy Demand Forecast
To enable capacity expansion modeling for the integrated planning process an hourly demand forecast was developed from this annual forecast. A separate hourly load profile was assigned to the annual baseline energy demand, energy efficiency and electrification load modifiers, and the IEPR Local Reliability alignment energy demands to get a complete hourly energy demand forecast for all scenarios.

Figure 90 details the sources used for converting the energy demand components to hourly demand profiles.

Figure 90. Hourly Demand Profile Components
Energy Demand Component Source for Hourly Demand Profile Baseline Energy Demand SVP Hourly Energy Demand Forecast 2023‐2035 Energy Efficiency 2022 IEPR Hourly Forecast – PG&E Planning Scenario Building Electrification from 2022 IEPR 2022 IEPR Hourly Forecast – PG&E Planning Scenario Building Electrification from Zero NOx Standard 2022 Electric Infrastructure Impacts from Proposed Zero NOx Standards report
Transportation Electrification 2022 IEPR Hourly Forecast – PG&E Planning Scenario IEPR Alignment (Local Reliability Scenario Only) SVP Hourly Energy Demand Forecast 2023‐2035 Hydrogen Price Forecasts2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   133
Appendix C. Hydrogen Price Forecasts
E3 developed an assessment of the cost trajectory of hydrogen that can be delivered to SVP’s service territory.

The hydrogen assessment in this analysis stems from E3’s and the University of California (UC) Irvine's work on the CEC’s The Challenge of Retail Gas in California’s Low Carbon Future Report. A set of cost and efficiency assumptions for the production of hydrogen using electrolysis was developed. The assumptions consist of inputs indexed by fuel, electrolysis technology, year, and level of industry learning assumed to occur between 2020 and 2050. Inputs consist of the levelized capital cost and annual fixed O&M cost, variable O&M cost, and overall energy efficiency, considering only renewable electricity as the energy input, including for heat input, if applicable.

Base Assumptions
E3 assumes alkaline electrolysis cell (AEC) as the primary means of producing green hydrogen59 due to its low cost and technologically mature attributes. 60  E3 developed two cost trajectories for AEC based on cumulative national installed capacity, as shown in Figure 91. 61 The Conservative cost trajectory is used in this study.

Figure 91. Electrolyzer Costs for Producing Hydrogen and SNG (Derived from E3’s work for the California Energy Commission (CEC, The Challenge of Retail Gas in California’s Low‐ Carbon Future) in partnership with UC Irvine. The secondary y‐axis shows the potential electrolyzer market size.) E3 assumed new off‐grid solar resources from Southern California to power electrolyzers to produce hydrogen. Hydrogen is assumed to be stored underground in lined rock caverns and piped to SVP’sservice 59 Hydrogen produced by breaking water into hydrogen and oxygen using an electric current in which electricity is renewable. 60 As opposed to producing clean hydrogen through a proton‐exchange membrane (PEM) or steam methane reforming or coal gasification with CCS. 61 Cost trajectories were developed in partnership with UC Irvine in 2019. https://www.ethree.com/at‐cec‐e3‐highlights‐need‐for‐gas‐ transition‐strategy‐in‐california/.

Hydrogen Price Forecasts2023 Integrated Resource Plan2023 Integrated Resource Plan 2023 Integrated Resource Plan   134
territory. New pipelines are assumed to be 400 miles long and are fully utilized by hydrogen producers and consumers beyond those modeled in this study. This assumption thereby spreads the cost of pipeline transportation more evenly across hydrogen produced by facilities modeled in this study. Hydrogen costs assumed in this study are delivered hydrogen costs and include production costs, new lined rock cavern underground storage, and new dedicated hydrogen pipelines.

All hydrogen plants that being operation between 2025 and 2035 are assumed to receive the full $3/kg 45V tax credit. The 45V tax credit is applied to all hydrogen production in the first 10 years of plants’ lives, but it’s impact is levelized across the entire 25‐year lifetimes of all plants. As a result, hydrogen costs from E3’s electrofuel spreadsheet should be treated as a PPA‐like cost, rather than the instantaneous cost of hydrogen each year.

Geothermal Limitations and Hydrogen Challenges Sensitivity Assumptions Compared to base assumptions, the sensitivity case studies a future with higher hydrogen costs. The electrolyzer technology is assumed to be proton exchange membrane electrolysis cell (PEMEC) instead of AEC. The electricity source for hydrogen production is assumed to be SoCal wind and the hydrogen pipelines are only half utilized.

See Figure 92 for the resulting hydrogen price forecast through 2035.

Figure 92. Hydrogen Price Forecast
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Appendix D. Standardized Tables
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City of Santa Clara
Agenda Report
1500 Warburton Avenue
Santa Clara, CA 95050
santaclaraca.gov
@SantaClaraCity
23-1117 Agenda Date: 12/5/2023

REPORT TO COUNCIL

SUBJECT
Public Hearing: Action on a Resolution Amending Rate Schedules for Electric Services for All Classes of Customers, Effective January 1, 2024

COUNCIL PILLAR
Deliver and Enhance High Quality Efficient Services and Infrastructure

BACKGROUND
The City of Santa Clara’s Electric Utility, Silicon Valley Power (SVP), is proposing a 10% increase to its rate schedules for all classes of customers, effective January 1, 2024. This proposed increase is necessary to maintain reserves at the minimum level, maintain cash balances, maintain sufficient funding for increases in the cost of power, and account for increases in cost of equipment, materials, and labor (for both new projects and required maintenance).

In addition, as previously communicated to the City Council, over the next three-to-four-year period, SVP will be recovering financially from the historic increases in gas prices and wholesale power prices that occurred starting in FY 2021/22 and continued during FY 2022/23. In FY 2021/22, even with one-time adjustments, actual expenditures exceeded revenues by approximately $4 million. In order to continue to address the impacts of the historic gas and wholesale power price increases, SVP took several actions during FY 2022/23 including using one-time and restricted funds, selling future gas hedges, and deferring capital projects which accounted for approximately $65 million to offset increased costs. While these actions addressed the increased costs, significant one-time solutions were necessary in order to bring FY 2022/23 expenditures in line with revenues. These same actions are not available to address the ongoing cost increases.

Current projections indicate that additional rate increases are necessary to continue to bring revenues closer to projected expenditure levels in the current year. Even with increases, given the volatility of energy prices, SVP’s ability to produce power locally, and other cost increases, the rate increases proposed in this report may be insufficient to fully cover expenses by year-end. If necessary, staff would explore the continued use of one-time solutions and/or bring in additional rate increases in the future to continue to address rising costs.

The rate increase is also needed so that SVP can maintain its financial health and bond ratings (AA- Stable assigned by Fitch and A+ Positive Outlook assigned by Standard and Poors) by having a balanced budget and adequate reserves to weather future market fluctuations and volatility.

DISCUSSION
The proposed 10% rate increase is needed to recover the increased cost of generating and delivering power to all SVP customers and to help ensure the long-term stability of the system. When the FY 2023/24 and FY 2024/25 Budget was developed, staff estimated a 7% rate increase effective January 1, 2024. After further analysis, staff is recommending a 10% increase. In summary, there are three key reasons for the proposed rate increase:

1. Recovery from the historic gas prices and increasing commodity costs

2. Increased materials and construction costs for maintenance and new projects

3. Maintaining reserves at minimum levels
Historic Gas Prices and Increasing Commodity Costs
As previously communicated, during last winter’s historic natural gas price spike, gas prices increased by up to 450% City of Santa Clara Page 1 of 5 Printed on 12/1/2023
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23-1117 Agenda Date: 12/5/2023
and power prices increased by up to 350% when compared to the previous winter. As an example, this caused a 60% or $166M increase in power costs in FY 2022/23 over FY 2021/22 ($131M is offset by higher revenue from power sales). As noted in the Background section, SVP took several one-time actions to offset the increases, but these same actions are not available to SVP in the event of a significant fluctuation in the future. Staff have developed a plan for recovery for these increased costs over the following three to four years. At this time, staff estimates another two to three years for full recovery, to bring reserves from the minimum level to recommended levels and have sufficient funds for the increased costs of ongoing operations, maintenance, and capital needs.

Staff has tracked the natural gas storage for our region using data from the U.S. Energy Information Administration. As of November, the reserves are almost 30% higher than they were during the same time last year in 2022. The CPUC also approved additional storage capacity for this year. The higher reserves combined with mild weather forecasts do not present the same market conditions and risks associated with last year’s historical prices. In addition, staff continue to monitor the futures pricing from SVP’s energy trading platforms and although prices remain high compared to historical averages, the market is not anticipating the same volatility as last year.

Lastly, a number of factors including material costs, permit complexity, and competitive markets are increasing the costs of Power Purchase Agreements (PPA). Recently two renewable energy project developers have requested renegotiation of executed PPA’s that would increase the contract price by approximately 50%.

Materials, Maintenance, and Construction Costs
Over the last 2 to 3 years the electric industry has seen significant cost increases that affect both maintenance and new construction. These costs have affected almost every facet of maintenance and construction projects. Some specific examples that reflect the increasing costs impacting SVP include:
· A 54% increase in costs of tree maintenance in FY 2022/23 versus FY 2020/21 (additional $1.2 million a year).

This increase results both from new legislation impacting hourly rates and from increased tree maintenance to reduce outages.
· Double and triple digit increases in the costs of materials such as cables, switches, and transformers for capital projects year over year. (Switches + Transformers)
- Increases of approximately 30% or $20+ million additional for the recent purchase of transformers for receiving station reconstruction.
- Overhead distribution transformers have increased in price by over 200% between 2021 and 2023. - Increase of over 35% in costs of wood poles between 2021 and 2023.

Reserves
The proposed rate increase is necessary to keep existing reserves at minimum levels. Additionally, SVP has the goal of building up an Infrastructure Reserve with a current target of $43 million. This is needed due to the volatility of capital projects and the number of unanticipated projects that occur as SVP improves preventative maintenance on aging infrastructure, especially power plants, substations, and transmission and distribution infrastructure. Below is a summary of the anticipated reserve levels:
· The Rate Stabilization Reserve is anticipated to be at the minimum target of 10% of sales revenue by June 30, 2024.
· The Operation and Maintenance Reserve is anticipated to be at its minimum target of 90 days of operating expenses by June 30, 2024.
· The new infrastructure reserve will be at less than 50% of minimum target.

In summary, the rate increase is projected to generate an additional $29 million in the current year's operating budget ($60 million ongoing annually). These funds will help cover the increase in current-year expenses, keep reserves at the minimum targets, and provide funding for contingencies or fluctuations.

Rate Increase Amounts
In compliance with Article XIIIC of the California Constitution (Proposition 26), the proposed rate increase will not result in the City’s electric rates exceeding the City’s reasonable cost to provide electric service to its customers.

Staff proposes that rates and charges for all classes of customers be increased on a uniform percentage basis City of Santa Clara Page 2 of 5 Printed on 12/1/2023
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23-1117 Agenda Date: 12/5/2023
because the underlying cost increases triggering this rate increase proposal have been incurred on behalf of all classes of existing customers. This approach is proposed for both policy and legal reasons. If the City were to apply the rate increase unequally it could be classified as a tax under Proposition 26. Under Proposition 26, a service rate is not a tax if it is imposed for a specific government service provided directly to a ratepayer and is not imposed on those not receiving the service. The courts have interpreted this to mean that no one rate class may subsidize another rate class. Therefore, in this case, to avoid characterization as a tax (which would require a vote of the people to approve), it is legally required that the increased cost of service be spread equally among the various classes of ratepayers.

The average monthly impact of the 10% rate increases by customer class and for the top 5 customers is provided as Attachment 2.

Residential Increase
For an average residential electric customer (averaging 430-kilowatt hours usage per month in FY 2022/23), with the proposed 10% increase, the customer’s electric bill will increase by approximately $6.50 per month (from $64.50 to $71.00) or approximately $78 a year. Residential bills for higher or lower usage levels will be proportionately larger or smaller.

For residential customers who have difficulty absorbing these increases, SVP provides a rate assistance program for income-qualified customers.

C-6 (Large Industrial) Increase
For the average C-6 large industrial customer, the customers’ electric bill will increase by approximately $250,000 a month or approximately $3.0 million a year. Bills for higher or lower usage levels will be proportionately larger or smaller.

Rate Comparisons
With the proposed increase, SVP will continue to have the lowest average system rates in California for utilities with more than 10,000 customers, based on U.S. Energy Information Administration’s Annual Electric Power Industry Report (Form EIA-861 for 2022 data). SVP’s rates will remain significantly below PG&E’s current rates.

SVP Proposed 2024 Rates Percentage Below PG&E Current Rates (09-01-23) Rate Type % Below Current
PG&E Rates
Residential 56%
Small Commercial 32%
Large Commercial 47%
Small Industrial 39%
Large Industrial 35%
Amending Rate Schedule C-1 (Small General Service) and Rate Schedule NM (Net Energy Metering)
In addition to the 10% rate increase for all customers, staff is also proposing to amend the current C1 rate schedule to allow unmetered accounts to be served under the C-1 rate schedule and to amend the NM rate schedule to update the 2024 payment rate for excess energy generated by solar facilities.

C-1 Rate schedule proposed change: The C-1 Rate applies to small commercial customers City of Santa Clara Page 3 of 5 Printed on 12/1/2023
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23-1117 Agenda Date: 12/5/2023
and metered service is the norm. However, on some occasions, metered service is not practical because energy consumption is extremely low, for example, bus shelter lighting.

Currently, there is no rate to properly address this type of usage. The proposed amendment allows an unmetered service to be classified under the C-1 rate schedule where a customer’s usage is expected to be below 385 watts and constant. The amended C-1 rate schedule allows SVP to bill such a customer at the same customer charge and energy rate as a metered customer except that the C-1 customer’s usage will be based on the estimated monthly usage. Overall, the proposed amendment is the best approach to ensure unmetered accounts pay their share of costs for electricity.

NM Rate schedule proposed change: Under the current NM rate, the compensation rate for energy produced by the customer that is more than the customer’s usage is based on an avoided renewable energy value charge. The avoided renewable energy value charge is equal to the average value of renewable energy credits used for SVP’s Green Power Program in 2022. SVP’s Green Power Program ended at the end of 2022. The proposed amendment changes the avoided renewable energy value charge to the average cost of unbundled renewable energy credits which SVP purchases for its compliance with the Renewable Portfolio Standard and other state and city renewable energy initiatives. This avoided costs calculation accurately reflects the value of excess renewable energy from net metering customers as it is now based on unbundled renewable energy. This ensures net metering customers are properly compensated.

CB-6 and CB-7 Rate Schedule Edit
This edit is to remove language referencing a separate Electric Sales Agreement (ESA) between specific customers and SVP. The CB-6 and CB-7 rate schedules were approved in 2018 and at that time the City had existing ESAs. The last ESA expired in December of 2020 and all such customers are now subject to the published rate schedules.

Upcoming Reserve Analysis Study and Cost of Service Study In September 2023, the City issued a request for proposals (RFP) for a Financial Condition Assessment of the City's Electric Utility. The selected consultant will do a comprehensive assessment of SVP’s financial position including risks, power costs, market information, and best practices to make recommendations about SVP’s reserves and cash position while addressing impacts to rates. A contract is anticipated to be awarded early 2024.

SVP will be issuing an RFP for a consultant to perform a Cost-of-Service Analysis (COSA). The objective of the COSA is to analyze costs and equitably assign those costs to customers in proportion with the cost of serving those customers.

The COSA study will detail the costs of providing utility service to the various customer classes served by SVP based upon the cost-causal relationship associated with specific expense items.

ENVIRONMENTAL REVIEW
The action being considered does not constitute a “project” within the meaning of the California Environmental Quality Act (“CEQA”) pursuant to section 15273 of Title 14 of the California Code of Regulations in that the proposed action is a modification of rates which is needed in order to meet operating expenses and maintain adequate cash reserves, and other reasons set forth in this staff report.

FISCAL IMPACT
The proposed 10% rate increase is anticipated to generate approximately $29 million additional revenue for the sixmonth period in Fiscal Year 2023/2024 and $60 million additional revenue in Fiscal Year 2024/2025. When the FY 2023/24 and FY 2024/25 Adopted Biennial Operating Budget was developed, a rate increase of 7% effective January 2024 was assumed. The proposed 10% increase would generate additional annual revenue of $18 million above the amount assumed in the Adopted Budget. These funds could be used to address any current year budget variances and/or increase reserve levels to better position SVP moving forward. Based on actual performance, budget actions are expected to be brought forward by year-end to adjust revenues, expenditures, and reserve levels.

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23-1117 Agenda Date: 12/5/2023

COORDINATION
This report has been coordinated with the Finance Department and City Attorney’s Office.

PUBLIC CONTACT
Public contact was made by posting the Council agenda on the City’s official-notice bulletin board outside City Hall Council Chambers. A complete agenda packet is available on the City’s website and in the City Clerk’s Office at least 72 hours prior to a Regular Meeting and 24 hours prior to a Special Meeting. A hard copy of any agenda report may be requested by contacting the City Clerk’s Office at (408) 615-2220, email [email protected] <mailto:[email protected]> <<mailto:[email protected]>> or at the public information desk at any City of Santa Clara public library.

In addition, Electric Utility staff have reached out to Key Accounts (large customers), commercial customers, school districts, numerous individual customers, City news and SVP news subscriptions by way of GovDelivery, and a posting in the Santa Clara Weekly. Staff have also disseminated information via social media: Nextdoor, X (formally Twitter) and Facebook.

RECOMMENDATION
Adopt a Resolution amending City Rate Schedules for Electric Utility Services to increase Electric Rates and Charges in each Rate Schedule by 10.0% and make other modifications, effective January 1, 2024.

Reviewed by: Manuel Pineda, Chief Electric Utility Officer Approved by: Jovan D. Grogan, City Manager

ATTACHMENTS

1. Resolution with attached Rate Schedules for Electric Services for All Classes of Customers

2. Monthly Bill Comparison Table - All Rate Schedules
City of Santa Clara Page 5 of 5 Printed on 12/1/2023
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Resolution/Electric Utility Rate Increase, Effective January 1, 2024 Page 1 of 3 Rev: 7/27/2023
RESOLUTION NO. _____

A RESOLUTION OF THE CITY OF SANTA CLARA, CALIFORNIA

AMENDING CITY RATE SCHEDULES FOR ELECTRIC UTILITY

SERVICE TO INCREASE ELECTRIC RATES AND CHARGES IN
EACH RATE SCHEDULE BY TEN PERCENT (10.0%) AND MAKE
OTHER MODIFICATIONS, EFFECTIVE JANUARY 1, 2024
WHEREAS, Chapter 13.05 of the Santa Clara City Code ("Code"), which is entitled Operation of an Electric Utility, provides that all electric energy and power furnished to customers of the Electric Department (“Electric Department”) of the City of Santa Clara, California, doing business as Silicon Valley Power, shall be supplied and charged to such customers, and paid for by such customers in accordance with certain electric rate schedules, tariffs, and rules and regulations adopted by the City Council;
WHEREAS, Section 13.05.040 of the Code further states that the City Council may, by resolution, review, revise, adopt and/or promulgate new or amended electric utility rate schedules from time to time as it deems necessary to meet the City’s contractual obligations and debt service requirements and to cover the cost of constructing, operating and maintaining the electric utility to serve the load;
WHEREAS, on November 22, 2023, and November 23, 2023, a notice of the public hearing regarding modifications to amend the City of Santa Clara Electric Rate Schedules ("Rate Schedules") was published in the Santa Clara Weekly and the San Jose Mercury News respectively;
WHEREAS, the Electric Department presented a Report To Council to the City Council (“Report to Council”) at its regularly scheduled meeting on December 5, 2023, to amend the Rate Schedules, which are attached hereto with proposed amendments and incorporated herein reference;
WHEREAS, the proposed ten percent (10.0%) increase to the rates and charges in the Rate Schedules are necessary to enable the Electric Department to (1) offset, among other things, (a) significant increase in power production and procurement cost; (b) increased transmission Resolution/Electric Utility Rate Increase, Effective January 1, 2024 Page 2 of 3 Rev: 7/27/2023
costs; (c) additional environmental and reliability requirements; and (d) transmission and distribution systems upgrade costs; and (2) maintain the Rate Stabilization Fund at the target level to maintain financial stability and the bond rating of the Electric Department; WHEREAS, the City Council reviewed the recommendations contained in the Report to Council, which include the recommendation to the City Council to amend the Rate Schedules for utility service to increase electric rates and charges in such Rate Schedules by ten percent (10.0%) beginning January 1, 2024; and
WHEREAS, the City Council has considered the evidence which was presented to it and concurs with the findings as set forth hereinabove to support the ten percent (10.0%) increase to the rates and charges in the Rate Schedules.

NOW THEREFORE, BE IT RESOLVED BY THE CITY OF SANTA CLARA AS FOLLOWS:

1. That the findings as set forth herein are hereby adopted by the City Council of the City of Santa Clara.

2. The Ten Percent (10%) increase to the rates and charges in the Rate Schedules and other amendments to the Rate Schedules shall be and are hereby adopted by the City Council of the City of Santa Clara, as reflected in the attachments hereto, effective January 1, 2024.

3. That a true and correct copy of the Resolution, including amended Rate Schedules, shall be kept on file in the Office of the City Clerk and in the Billing Division of the City Finance Department at all times while the Rate Schedules are effective and, until further amended or replaced, shall be open to public investigation and inspection during the regular business hours of such offices.
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Resolution/Electric Utility Rate Increase, Effective January 1, 2024 Page 3 of 3 Rev: 7/27/2023

4. Effective date. This resolution shall become effective immediately.

I HEREBY CERTIFY THE FOREGOING TO BE A TRUE COPY OF A RESOLUTION PASSED

AND ADOPTED BY THE CITY OF SANTA CLARA, CALIFORNIA, AT A REGULAR MEETING THEREOF HELD ON THE ___ DAY OF _________, 2023, BY THE FOLLOWING VOTE:

AYES: COUNCILORS:

NOES: COUNCILORS:

ABSENT: COUNCILORS:

ABSTAINED: COUNCILORS:

ATTEST: ______________________________

NORA PIMENTEL, MMC

ASSISTANT CITY CLERK

CITY OF SANTA CLARA
Attachments incorporated by reference:

1. Rate Schedules for Electric Services to be Effective January 1, 2024

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE A

MUNICIPAL WATER DEPARTMENT
Sheet 1 of 1
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 DESCRIPTION OF SERVICE:

The schedule is applicable to electricity used by the Municipal Water Department for water and sewer pumping service.

RATES:

All kWh, per kWh $ 0.13837
SURCHARGE:

Public Benefits Charge and State Surcharge, as set forth in Note A, will be added to the above charge.

NOTES:
(A) SURCHARGES:

PUBLIC BENEFITS CHARGE:

The Public Benefits Charge is a state required non-bypassable surcharge imposed on all sales of electricity and electrical services. It is used to fund public goods research, development, and demonstration, as well as, energy efficiency activities, renewable energy and low income assistance programs. The surcharge is equal to kWh billed times 2.85%.

STATE SURCHARGE: The state surcharge is required by California state law, and supports funding for the California Energy Commission. The surcharge is equal to kWh billed times the State Surcharge Rate. The current State Surcharge Rate can be found on SVP’s website at:
http://www.siliconvalleypower.com/svp-and-community/rules-and-regulations

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE C-1

GENERAL SERVICE
Sheet 1 of 2
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023

Resolution No. 23-9233
DESCRIPTION OF SERVICE:

This schedule is applicable to alternating current service through one meter, for power and heating alone or combined with lighting. This schedule is applicable to customers who do not qualify for Schedule D-1, CB-1, CB-3, CB-6, CB-7 or CB-8. The Time of Use (TOU) Option is available to all customers. Customers who utilize the TOU option will be responsible for the installed cost of a TOU meter, as set forth in Note (B) below.

RATES: Non-Time of Use Time of Use Option
SINGLE-PHASE SERVICE:

CUSTOMER CHARGE, per meter per month: $ 5.06 $ 5.06
ENERGY CHARGE: (In addition to the Customer Charge)
Peak Off-Peak
First 800 kWh, per kWh $ 0.24377 $0.26528 $0.22616
Excess Over 800 kWh, per kWh $ 0.22130 $0.24280 $0.20369 MINIMUM CHARGE: $5.06 per meter per month but not less than $3.14 per month per kVA of connected welder load, rectifier load, x-ray and x-ray type equipment load, fusing machine load, and other types of welding equipment load.

THREE-PHASE SERVICE: The single-phase rate plus $3.96 per meter per month.

MINIMUM CHARGE: $9.02 per month, but not less than $3.14 per month per kVA of connected welder load and per horsepower of polyphaser connected load, rectifier load, x-ray and x-ray type equipment load, fusing machine load, and other types of welding load.

SURCHARGES:

Public Benefits Charge and State Surcharge, as set forth in Note A, will be added to the above charges.

NOTES:
(A) SURCHARGES:

PUBLIC BENEFITS CHARGE:

The Public Benefits Charge is a state required non-bypassable surcharge imposed on all sales of electricity and electrical services. It is used to fund public goods research, development, and demonstration, as well as, energy efficiency activities, and low income assistance programs. The surcharge is equal to the sum of the Customer Charge and the Energy Charge times 0.0285.

STATE SURCHARGE: The state surcharge is required by California state law, and supports funding for the California Energy Commission. The surcharge is equal to kWh billed times the State Surcharge Rate.

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE C-1

GENERAL SERVICE
Sheet 2 of 2
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023

Resolution No. 23-9233
The current State Surcharge Rate can be found on SVP’s website at:
http://www.siliconvalleypower.com/svp-and-community/rules-and-regulations .
(B) TIME OF USE (TOU) OPTION:

Customers who select the time of use option will pay a one-time TOU Meter Installation Charge, which is the cost of a TOU meter, plus its installation cost. This Charge is set forth in the City of Santa Clara Municipal Fee Schedule. The manufacturer and model of such meter shall be at the sole discretion of Silicon Valley Power. Time of use periods are as set forth below:

Peak Period: Monday through Saturday, except holidays (New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, Christmas Day), beginning at 6:00 AM and ending at 10:00 PM.

Off-Peak Period: All other hours.

The TOU meter is used to measure kWh usage in the peak and off-peak periods. The ratio of peak kWh to total kWh will be used to determine the portion of the First 800 kWh that falls in the peak period. This ratio will also be used to determine the portion of kWh usage above 800 kWh that falls in the peak period. (C) UNMETERED SERVICE:

A customer may request electric service under this rate schedule on an unmetered basis, and SVP may, in sole discretion, allow such service if SVP determines (1) customer qualifies to receive service under this rate schedule and an existing unmetered SVP rate schedule does not apply to customer; (2) customer’s connected load is less than 385 watts; (3) customer’s usage is expected to be constant; and (4) installation of a meter to serve customer’s connected load is not practical. If SVP determines customer may receive electric service under this rate schedule on an unmetered basis, customer shall pay the customer charge and the energy charge above. The energy charge shall be assessed on customer’s estimated monthly usage which shall be determined as follows: customer’s estimated connected load in watts times 8,760, divided by 1000, and then divided by 12. Customer shall be responsible for notifying the SVP not less than 30 days in advance of any change in customer’s connected load. Failure to provide such notification may result in the SVP terminating electric service to the customer.

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE CB-1

GENERAL SERVICE DEMAND

METERED
Sheet 1 of 3
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 DESCRIPTION OF SERVICES:

This schedule is applicable to commercial or industrial services whose monthly use of energy has exceeded 8,000 kWh for three (3) consecutive months, or where the initial connected load indicates use above 8,000 kWh per billing period. When either of these qualifications has been met, this schedule as well as a Maximum Demand meter will be installed as promptly as is practicable. Both the Schedule CB-1 and the Maximum Demand meter will be continued in service until the monthly use of energy has fallen below 6,000 kWh for 12 consecutive months. At that time, and at the option of Silicon Valley Power, Schedule C-1 will be applicable and the Maximum Demand meter may be removed. The Time of Use Option is available to all customers. Customers who utilize the TOU option will be responsible for the installed cost of a TOU meter, if necessary, as set forth in Note (E) below.

RATES: Non-Time of Use Time of Use
CUSTOMER CHARGE, per meter per month $91.99 $91.99

DEMAND CHARGE:

Time of Use
Peak Off-Peak
All kW of Billing Demand, per kW $11.11 $11.11 $0.00
ENERGY CHARGE: Non-Time of Use Time of Use
Peak Off-Peak
All kWh, per kWh $0.14779 $0.16932 $0.13019

SURCHARGES:

Public Benefits Charge and State Surcharge, as set forth in Note D, will be added to the above charges.

NOTES:
(A) MAXIMUM DEMAND:

The Maximum Demand in any month will be the average kW delivery of the 15-minutes interval in which such delivery is greater than in any other 15-minute interval in the month, provided, however, that in case the load is intermittent or subject of violent fluctuations, Silicon Valley Power may use a 5-minute interval instead of a 15-minute interval.
(B) BILLING DEMAND:

The Billing Demand to be used in computing charges under this schedule will be the mean of the Maximum Demand for the current month and the highest such demand occurring in the year ending with current month.

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE CB-1

GENERAL SERVICE DEMAND

METERED
Sheet 2 of 3
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 (C) VOLTAGE:

Single-phase or three-phase service on this schedule will be supplied at the secondary voltage available, or at the option of the customer, at the primary voltage available, subject to the rules and regulations for electric service.
(D) SURCHARGES:

PUBLIC BENEFITS CHARGE: The Public Benefits Charge is a state required non-bypassable surcharge imposed on all sales of electricity and electrical services. It is used to fund public goods research, development, and demonstration, as well as, energy efficiency activities, and low income assistance programs. The surcharge is equal to the sum of the Customer Charge, Demand Charge and Energy Charge, including adjustment for Primary Voltage and Power Factor, times 0.0285.

STATE SURCHARGE: The state surcharge is required by California state law, and supports funding for the California Energy Commission. The surcharge is equal to kWh billed times the State Surcharge Rate.

The current State Surcharge Rate can be found on SVP’s website at:
http://www.siliconvalleypower.com/svp-and-community/rules-and-regulations (E) TIME OF USE OPTION:

Customers who select the time of use option will pay a one-time TOU Meter Installation Charge, which reflects the cost difference (including installation) between a non-time of use meter and a time of use meter. This Charge is set forth in the City of Santa Clara Municipal Fee Schedule. The manufacturer and model of such meter shall be at the sole discretion of Silicon Valley Power. Time of use periods are as set forth below:

Peak Period: Monday through Saturday, except holidays (New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, Christmas Day), beginning at 6:00 AM and ending at 10:00 PM.

Off-Peak Period: All other hours.

The TOU meter is used to measure kWh and kW in the peak and off-peak periods. (F) PRIMARY VOLTAGE DISCOUNT:

When delivery is made at the same voltage as that of the distribution line from which the service is supplied, a discount of $1.39 per kW of Billing Demand for 12kV line voltages will be allowed, provided, however, Silicon Valley Power is not required to supply service at a particular line voltage where it has (or will install) ample facilities for supplying at another voltage equally or better suited to the customer's

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE CB-1

GENERAL SERVICE DEMAND

METERED
Sheet 3 of 3
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 electrical requirements. Silicon Valley Power retains the right to change its line voltage at any time, after reasonable advance notice to any customer receiving a discount hereunder and affected by such change, and such customer then has the option to change their system so as to receive service at the new line voltage or to accept service (without voltage discount) through transformers to be supplied by Silicon Valley Power.
(G) POWER FACTOR:

When the Billing Demand has exceeded 300 kW for three consecutive months and thereafter until it has fallen below 200 kW for twelve consecutive months, bills will be adjusted for weighted monthly average Power Factor as follows:

The sum of Customer Charge, Demand Charge, Energy Charge, Primary Voltage Discount (as applicable) for any month as computed on the above rates will be decreased or increased, respectively, by 0.1 % for each 1 % that the average Power Factor is greater or less than 85%. Such average Power Factor to be computed (to the nearest whole percent) from the ratio of lagging kilovolt-ampere-hours to kilowatt- hours consumed in the month.
(H) OFF-PEAK DEMAND – NON TIME OF USE:

Any customer may, upon request, have their Maximum Demand measured by a recording type meter, and all demands occurring between 10:00 PM and 6:00 AM of the following day and on Sundays and legal holidays will not be counted in determining the Billing Demand.

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE CB-3

LARGE GENERAL SERVICE DEMAND

METERED
Sheet 1 of 3
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233

DESCRIPTION OF SERVICE
This schedule is applicable to industrial and commercial services whose monthly billing demands have exceeded 4,000 kilowatts for three consecutive months, or where the initial connected load indicates a demand above 4,000 kilowatts. Customers served under this Schedule CB-3 will be continued in service until the monthly billing demand has fallen below 4,000 kilowatts for 12 consecutive billing periods. The Time of Use Option is available to all customers. Customers who utilize the TOU option will be responsible for the installed cost of a TOU meter, if necessary, as set forth in Note (E) below.

RATES: Non-time of use Time of Use
CUSTOMER CHARGE – per meter per month $91.99 $91.99
DEMAND CHARGE: Non-time of use Time of Use
Peak Off-Peak
All kW of Billing Demand, per KW $14.83 $14.83 $0.00
ENERGY CHARGE: Non-time of use Time of Use
Peak Off-Peak
All kWh, per kWh $0.13611 $0.15760 $0.11848
SURCHARGES:

Public Benefits Charge and State Surcharge, as set forth in Note D, will be added to the above charges.

NOTES:
(A) MAXIMUM DEMAND:

The Maximum Demand in any month will be the average kW delivery of the 15-minute interval in which such delivery greater than in any other 15-minute interval in the month, provided, however, that in case the load is intermittent or subject to violent fluctuations, Silicon Valley Power may use a 5-minute instead of a 15-minute interval.
(B) BILLING DEMAND:

The Billing Demand to be used in computing charges under this schedule will be the mean of the actual Maximum Demand for the current month and the highest such demand occurring in the year ending with the current month.
(C) VOLTAGE:

Service on this schedule will be supplied at the primary voltage available or, at the option of Silicon Valley Power, at the secondary voltage available, subject to the rules and regulations for electric service.

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE CB-3

LARGE GENERAL SERVICE DEMAND

METERED
Sheet 2 of 3
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 (D) SURCHARGES:

PUBLIC BENEFITS CHARGE:

The Public Benefits Charge is a state required non-bypassable surcharge imposed on all sales of electricity and electrical services. It is used to fund public goods research, development, and demonstration, as well as, energy efficiency activities, and low income assistance programs. The surcharge is equal to the sum of the Customer Charge, Demand Charge, and Energy Charge, including adjustment for Power Factor and Primary Voltage, times 0.0285.

STATE SURCHARGE: The state surcharge is required by California state law, and supports funding for the California Energy Commission. The surcharge is equal to kWh billed times the State Surcharge Rate.

The current State Surcharge Rate can be found on SVP’s website at:
http://www.siliconvalleypower.com/svp-and-community/rules-and-regulations (E) TIME OF USE OPTION:

Customers who select the time of use option will pay a one-time TOU Meter Installation Charge, which reflects the cost difference (including installation) between a non-time of use meter and a time of use meter. This Charge is set forth in the City of Santa Clara Municipal Fee Schedule. The manufacturer and model of such meter shall be at the sole discretion of Silicon Valley Power. Time of use periods are as set forth below:

Peak Period: Monday through Saturday, except holidays (New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, Christmas Day), beginning at 6:00 AM and ending at 10:00 PM.

Off-Peak Period: All other hours.

The TOU meter is used to measure kWh and kW in the peak and off-peak periods. (F) PRIMARY VOLTAGE DISCOUNT:

When delivery is made at the same voltage as that of the distribution line from which the service is supplied, a discount of $1.39 per kW of Billing Demand for 12kV or higher available line voltages will be allowed, provided, however, Silicon Valley Power is not required to supply service at a particular line voltage where it has (or will install) ample facilities for supplying at another voltage equally or better suited to the customer's electrical requirements. Silicon Valley Power retains the right to change its line voltage at any time, after reasonable advance notice to any customer receiving a discount hereunder and affected by such change, and such customer then has the option to change their system so as to receive service at the new line voltage or to accept service (without voltage discount) through transformers to be supplied by Silicon Valley Power.

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE CB-3

LARGE GENERAL SERVICE DEMAND

METERED
Sheet 3 of 3
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 (G) POWER FACTOR:

The sum of Customer Charge, Demand Charge, Energy Charge, Primary Voltage Discount (as applicable) for any month as computed on the above rates will be decreased or increased, respectively, by 0.1 % for each 1 % that the average Power Factor is greater or less than 85%. Such average Power Factor to be computed (to the nearest whole percent) from the ratio of lagging kilovolt-ampere-hours to kilowatt- hours consumed in the month, provided, however, that no Power Factor correction will be made for any month when customer's Maximum Demand is less than 10% of the highest demand in the preceding eleven months.
(H) OFF-PEAK DEMAND:

Any customer served under this Rate Schedule may, upon request, have their Maximum Demand measured by a recording type meter, and all demands occurring between 10:00 P.M. and 6:00 A.M. of the following day and on Sundays and legal holidays will be discounted in determining the Billing Demand.

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE CB-6

LARGE COMBINED GENERAL

SERVICE
Sheet 1 of 3
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233

DESCRIPTION OF SERVICE
This Schedule is optional to Customers who occupy one or more demand-metered service addresses served by Silicon Valley Power (SVP), where electric service from SVP is in Customer’s name, and where Customer’s combined monthly electric billing demand is 5,000 kW or more. Customers with self-generation may also be subject to Schedule SB-1. Customers who select this rate option will need to provide at least one month written notice and continue with this rate option for at least one year.

RATE OPTIONS: Non Time of Use Time of Use

CUSTOMER CHARGE
For Each Service Address – per meter per month $429.02 $429.02 DEMAND CHARGE:

Peak Off-Peak
All kW of Billing Demand, per kW: $27.03 $27.03 $0.00
ENERGY CHARGE:

First 5,000,000 kWh, per kWh $0.10287 $0.11223 $0.09856 Next 10,000,000 kWh, per kWh $0.10010 $0.10946 $0.09579 Next 5,000,000 kWh, per kWh $0.09453 $0.10390 $0.09023
Over 20,000,000 kWh, per kWh $0.08620 $0.09557 $0.08190 SURCHARGES:

Public Benefits Charge and State Surcharge, as set forth in Note E, will be added to the above charges.

NOTES:
(A) MAXIMUM DEMAND
The Maximum Demand in any month will be the sum of the highest average kW delivery, at each service address, of any 15-minute interval occurring between 1:00 PM and 10:00 PM Monday through Saturday, excluding holidays. However, in case the load is intermittent or subject to violent fluctuations, Silicon Valley Power may use a 5-minute interval instead of a 15-minute interval. (B) BILLING DEMAND
The Billing Demand to be used in computing charges under this schedule will be sum of the mean of the actual Maximum Demand for the current month at each service address and the highest such demand occurring in the year ending with the current month at each service address, but not less than 5,000 kw.
(C) VOLTAGE ADJUSTMENT:

For each Service Address served at less than 12,000 volts, the Demand Charge will be increased by $1.39 per kW. For each Service Address served at 60,000 volts directly from a customer owned

CITY OF SANTA CLARA
RATE SCHEDULE CB-7

LARGE COMBINED GENERAL
SERVICE – MARKET BASED OPTION
Sheet 1 of 6
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233

DESCRIPTION OF SERVICE
This Schedule is optional to Customers who occupy one or more demand-metered service addresses served by Silicon Valley Power (SVP), where electric service from SVP is in Customer’s name, and where Customer’s combined monthly electric billing demand is 5,000 kW or more. Customers with self-generation may also be subject to Schedule SB-1. Under this Schedule, Customers may designate a portion of their monthly energy purchased from SVP to be priced based on Note H. Customer who select this rate option will continue with this option for the full kWh volume subscribed for at least one year. Customer must also provide at least three months’ written notice to terminate this option and to be billed under other applicable rate schedule. The total combined energy for all SVP customers that may be served under this rate schedule is 30,000,000 kWh per month.

RATE OPTIONS: Non Time of Use Time of Use

CUSTOMER CHARGE
For Each Service Address – per meter per month $429.02 $429.02 DEMAND CHARGE:

Peak Off-Peak
All kW of Billing Demand, per kW: $27.03 $27.03 $0.00
ENERGY CHARGE:

First 5,000,000 kWh, per kWh $0.10287 $0.11223 $0.09856 Next 10,000,000 kWh, per kWh $0.10010 $0.10946 $0.09579 Next 5,000,000 kWh, per kWh $0.09453 $0.10390 $0.09023
Over 20,000,000 kWh, per kWh $0.08620 $0.09557 $0.08190 MARKET-BASED PRICING ADJUSTMENT: See NOTE H
SURCHARGES:

Public Benefits Charge and State Surcharge, as set forth in Note E, will be added to the above charges.

NOTES:
(A) MAXIMUM DEMAND
The Maximum Demand in any month will be the sum of the highest average kW delivery, at each service address, of any 15-minute interval occurring between 1:00 PM and 10:00 PM Monday through Saturday, excluding holidays. However, in case the load is intermittent or subject to violent fluctuations, Silicon Valley Power may use a 5-minute interval instead of a 15-minute interval. (B) BILLING DEMAND

CITY OF SANTA CLARA
RATE SCHEDULE CB-7

LARGE COMBINED GENERAL
SERVICE – MARKET BASED OPTION
Sheet 2 of 6
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 The Billing Demand to be used in computing charges under this schedule will be sum of the mean of the actual Maximum Demand for the current month at each service address and the highest such demand occurring in the year ending with the current month at each service address, but not less than 5,000 KW.
(C) VOLTAGE ADJUSTMENT:

For each Service Address served at less than 12,000 volts, the Demand Charge will be increased by $1.39 per kW. For each Service Address served at 60,000 volts directly from a customer owned substation or from a SVP-owned substation directly paid for by customer, the Demand Charge will be reduced by $1.74 per kW. However, Silicon Valley Power is not required to supply service at a particular line voltage where it has (or will install) ample facilities for supplying at another voltage equally or better suited to the customer's electrical requirements. Silicon Valley Power retains the right to change its line voltage at any time, after reasonable advance notice to any customer receiving a discount hereunder and affected by such change, and such customer then has the option to change their system so as to receive service at the new line voltage or to accept service (without voltage discount) through transformers to be supplied by Silicon Valley Power.
(D) POWER FACTOR ADJUSTMENT:

For each service address where Billing Demand has exceeded 300 kW for three consecutive months bills will be adjusted for weighted monthly average Power Factor as follows: the sum of Customer Charge, Demand Charge, Energy Charge, Secondary Voltage Adjustment (as applicable) and 60kV Delivery Adjustment (as applicable) for any month as computed on the above rates will be decreased or increased, respectively, by 0.1 % for each 1 % that the average Power Factor is greater or less than 85%. Such average Power Factor to be computed (to the nearest whole percent) from the ratio of lagging kilovolt-ampere-hours to kilowatt- hours consumed in the month, provided, however, that no Power Factor correction will be made for any month when the Maximum Demand of such service address, is less than 10% of the highest demand in the preceding eleven months.

Power Factor Adjustment will be discontinued for any service address that falls below 200 kW for 12 consecutive months.
(E) SURCHARGES:

PUBLIC BENEFITS CHARGE:

The Public Benefits Charge is a state required non-bypassable surcharge on all sales of electricity and electrical services. It is used to fund public goods research, development, and demonstration, as well as, energy efficiency activities, renewable energy, and low income assistance programs. The surcharge is equal to the sum of the Meter Charge and Capacity Reservation Charge, times 0.0285.

STATE SURCHARGE:

CITY OF SANTA CLARA
RATE SCHEDULE CB-7

LARGE COMBINED GENERAL
SERVICE – MARKET BASED OPTION
Sheet 3 of 6
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 The State Surcharge is required by California state law, and supports funding for the California Energy Commission. The surcharge is equal to kWh billed times the State Surcharge Rate. The current State Surcharge Rate can be found on SVP’s website at:
http://www.siliconvalleypower.com/svp-and-community/rules-and-regulations (F) CALCULATION OF ENERGY CHARGES AT EACH SERVICE ADDRESS:

The energy charges calculated under this Schedule CB-7 will be apportioned to each service address as follows:

1. Energy Charges for each service address will be determined as the ratio of the kWh usage at each service address divided by the sum of kWh usage at all applicable service addresses.

2. After such apportionment, each service address will be subject to the applicable Voltage Adjustment, Power Factor Adjustment, Public Benefits Charge and State Surcharge provisions set forth above.

3. Payment for bills rendered at each service address shall be made by wire transfer, automated clearing house (ACH) transfer, check or credit card. Payments made by credit card will be subject to the applicable credit card transaction fees.
(G) TIME OF USE OPTION:

Customers who select the time of use option will need to provide at least one month written notice and continue with this option for at least one year. Customers who select the time of use option will pay a one-time TOU Meter Installation Charge, which reflects the cost difference (including installation) between a non-time of use meter and a time of use meter. This Charge is set forth in the City of Santa Clara Municipal Fee Schedule. The manufacturer and model of such meter shall be at the sole discretion of Silicon Valley Power. Time of use periods are as set forth below:

Peak Period: Monday through Saturday, except holidays (New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, Christmas Day), beginning at 1:00 PM and ending at 10:00 PM.

Off-Peak Period: All other hours. The TOU meter is used to measure kWh and kW in the peak and off-peak period.
(H) MARKET BASED PRICING ADJUSTMENT (MBPA):

Upon at least 30 days’ notice, customers may designate up to 100%, but not less than 2,000,000 kWh of their monthly usage to be priced based on market indices as set forth below. The total combined amount of energy that may be available (Total Available) to all Customers under this MBPA shall be determined solely by SVP and it’s on a first come first serve basis. SVP shall give 90 days’ notice of any change in such total amount, and endeavor to make such changes effective January 1 of each calendar year. If the Total Available is changed to an amount lower than actually being allowed, SVP

CITY OF SANTA CLARA
RATE SCHEDULE CB-7

LARGE COMBINED GENERAL
SERVICE – MARKET BASED OPTION
Sheet 4 of 6
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 will reduce existing customers’ allowable amounts on a prorated basis, and this schedule will be closed to new customers.

Market Based Pricing Adjustment is calculated as the Market Cost Adjustment Rate times the full kWh subscribed under this rate option. The Market Cost Adjustment Rate is the Current Market Cost of Energy minus the Base Energy Rate. Such difference may be positive or negative.

The Current Market Cost of Energy is determined as set forth in the CB-7 Market Based Option Bill Determinants attached here and as posted. The Current Market Cost of Energy for each calendar month will be sent to Customer served under this option with the monthly bill.

The Base Energy Rate is reflected in the above Energy Charge rates, and is SVP’s determination of the annualized unit cost that a creditworthy customer would incur for receiving bundled energy with renewable and GHG characteristics from publicly owned energy service providers like SVP. The Base Energy Rate will be updated annually in conjunction with changes in the Energy Charge rates.

The Market Based Pricing Adjustment, which can be positive or negative, will be applied to the Energy Charge prior to Voltage Adjustment, Power Factor Adjustment and Surcharges. .

CITY OF SANTA CLARA
RATE SCHEDULE CB-7

LARGE COMBINED GENERAL
SERVICE – MARKET BASED OPTION
Sheet 5 of 6
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 CB-7 MARKET BASED OPTION BILL DETERMINANTS
The total combined amount of energy that is available (Total Available) to all Customers under MBPA for Calendar Year 2024 is 30,000,000 kWh per month.

Base Energy Rate for Calendar Year 2024 is $0.08015 per kWh.

Current Market Cost of Energy includes:

1. PG&E Hourly DLAP Price which is the CAISO DLAP_PGAE - APND for the Day Ahead Market (DAM). If any hourly DLAP Price is less than zero, the effective DLAP price for such hour shall be zero.

2. Transmission loss which is 2% of PG&E Hourly DLAP price calculated above.

3. CAISO High Voltage Transmission Access Charge (“HV TAC”) for month ($/MWh) The CAISO HV TAC price is the daily average PG&E effective HV TAC rate for Santa Clara for the applicable month, and is obtained using the following site(s) information:
http://www.caiso.com/market/Pages/Settlements/Default.aspx

4. CAISO Low Voltage Transmission Access Charge (“LV TAC”) price is the daily average PG&E effective LV TAC rate for Santa Clara for the applicable month, and is obtained using the following site(s) information:
http://www.caiso.com/market/Pages/Settlements/Default.aspx.

5. Market Price of Renewable Energy Credit =
Market price of RECs for Month * 45% (SVP applicable RPS percentage for current compliance year) The average monthly market price of RECs is obtained using the following site(s) information:

The data for California Bucket 1, 2, and 3 RECs are obtained from Megawatt Daily. The average monthly market price is then calculated based on SVP weighted average for Bucket 1, 2 and 3 RECs.

For current compliance year, the Bucket 1 is 75%, Bucket 2 is 15% and Bucket 3 is 10%.

CITY OF SANTA CLARA
RATE SCHEDULE CB-7

LARGE COMBINED GENERAL
SERVICE – MARKET BASED OPTION
Sheet 6 of 6
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233

6. CAISO Grid Management Charge (“GMC”) ($/MWh) = Charge Code 4560 (Market Services Charge) + Charge Code 4561 (System Operations Charge)
The CAISO GMC is obtained using the following site(s) information (and will be updated as it is updated at the CAISO:
http://www.caiso.com/market/Pages/Settlements/Default.aspx If any of the sources for the above described rate components are no longer available, SVP will diligently seek an alternative but equivalent source for that rate component.

If new or additional components affect the Current Market Cost of Energy due to new legislation or other circumstances, bill determinants will be added or adjusted to reflecting any impacting mandates or regulations. Customers will be provided notification of such additions or adjustments no less than 30 days prior to implementation. .

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE CB-8

CUSTOMER LOAD RETENTION
Sheet 1 of 1
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233

DESCRIPTION OF SERVICE
This rate schedule is available to customers eligible for service under Schedules CB-6 or CB-7 who, but for the provisions of this rate schedule, would cease operations in the City of Santa Clara, and would not engage in any substantially similar operation in the State of California for a period of at least five years. Customer must submit a signed affidavit attesting to this effect. The cumulative maximum billing demand for all SVP customers that may be served under this rate schedule at any one time is 20,000 kW.

RATES:

Customers’ bills under Schedule CB-6 or CB-7, prior to Public Benefit Charge and State Surcharge, will be reduced by up to 12% for a period of not more than five years. The effective percentage reduction and the term of such percentage reduction, will be as approved by the Chief Electric Utility Officer.

NOTES:

1. Marginal Cost to Serve:

In no event shall service under this rate schedule result in customer being served at less than SVP’s marginal cost of providing service to said customer.

2. Forfeiture of Discounts:

If a customer fails to comply with the terms of this rate schedule, SVP will seek repayment of the dollar amount of all discounts provided under this rate schedule.

3. First Come, First Served:

This rate schedule is available on a first come, first served basis on a monthly basis. However, preference will be given to customers with a long history of doing business in Santa Clara, to customers that help SVP maintain a diversified sales base, and to the number and type of jobs that may be preserved.

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE D-1

DOMESTIC SERVICE
Sheet 1 of 2
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233

DESCRIPTION OF SERVICE
This schedule is applicable to single phase residential service for single-family dwellings, condominium house meters, townhouse house meters, cooperative apartment house meters, flats and apartments separately metered by Silicon Valley Power. The Time of Use (TOU) Option is available to all customers. Customers who utilize the TOU option will be responsible for the installed cost of a TOU meter, as set forth in Note (B) below.

This schedule is not applicable for services to common areas of apartment houses.

RATES: Non-Time of Use Time of Use Option

METER CHARGE, per meter per month $4.68 $4.68

ENERGY CHARGE (to be added to the Customer Charge)
Non-Time of Use Time of Use Option
Peak Off-Peak
First 300 kWh, per kWh $0.14297 $0.16447 $0.12536
Excess Over 300 kWh, per kWh $0.16434 $0.18585 $0.14673

SURCHARGES
Public Benefits Charge and State Surcharge, as set forth in Note A, will be added to the above charges.

NOTES:
(A) SURCHARGES:

PUBLIC BENEFITS CHARGE: The Public Benefits Charge is a state required non-bypassable surcharge imposed on all sales of electricity and electrical services. It is used to fund public goods research, development, and demonstration, as well as, energy efficiency activities, renewable energy and low income assistance programs. The surcharge is equal to the sum of the Meter Charge and the Energy Charge times 0.0285.

STATE SURCHARGE: The state surcharge is required by California state law, and supports funding for the California Energy Commission. The surcharge is equal to kWh billed times the State Surcharge Rate.

The current State Surcharge Rate can be found on SVP’s website at:
http://www.siliconvalleypower.com/svp-and-community/rules-and-regulations

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE D-1

DOMESTIC SERVICE
Sheet 2 of 2
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 (B) TIME OF USE (TOU) OPTION:

Customers who select the time of use option will pay a one-time TOU Meter Installation Charge, which is the cost of a TOU meter, plus its installation cost. This Charge is set forth in the City of Santa Clara Municipal Fee Schedule. The manufacturer and model of such meter shall be at the sole discretion of Silicon Valley Power. Time of use periods are as set forth below:

Peak Period: Monday through Saturday, except holidays (New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, Christmas Day), beginning at 6:00 AM and ending at 10:00 PM.

Off-Peak Period: All other hours.

The TOU meter is used to measure kWh usage in the peak and off-peak periods. The ratio of peak kWh to total kWh will be used to determine the portion of the First 300 kWh that falls in the peak period. This ratio will also be used to determine the portion of kWh usage above 300 kWh that falls in the peak period.

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE IC

IRRIGATION CONTROLLER SERVICE
Sheet 1 of 2
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 APPLICATION:

This schedule is applicable to non-metered service to irrigation controller or sprinkler controllers located either in public streets, highways, and places, or private areas.

RATES:

SERVICE CHARGE:

For each sprinkler or irrigation controller $9.49 per unit per month MINIMUM CHARGE: $9.49 per month
SURCHARGES:

Public Benefits Charge and State Surcharge, as set forth in Note A, are included in the above charge.

NOTES:
(A) SURCHARGES:

PUBLIC BENEFITS CHARGE:

The Public Benefits Charge is a state required non-bypassable surcharge imposed on all sales of electricity and electrical services. It is used to fund public goods research, development, and demonstration, as well as, energy efficiency activities, renewable energy, and low income assistance programs. The surcharge is equal to 2.85% of the otherwise applicable rate.

STATE SURCHARGE: The state surcharge is required by California state law, and supports funding for the California Energy Commission. The surcharge is equal to estimated kWh per controller times the State Surcharge Rate. The current State Surcharge Rate can be found on SVP’s website at:
http://www.siliconvalleypower.com/svp-and-community/rules-and-regulations (B) TYPE OF SERVICE:

Energy will be supplied at 120 volts, single phase, two wire service. Where only other voltages are available, applicant shall pay, in advance, Silicon Valley Power's cost to convert from the available voltage to 120 volts.
(C) POINT OF DELIVERY:

Delivery will be made from Silicon Valley Power's existing electric lines at a point mutually agreed upon, without extension thereof to customer's system.

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE IC

IRRIGATION CONTROLLER SERVICE
Sheet 2 of 2
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 (D) SERVICE CONNECTION:

Silicon Valley Power will provide overhead or underground service in accordance with the current Rules and Regulations for Electric Service. However, applicant shall pay to Silicon Valley Power, in advance, the amount, if any, by which Silicon Valley Power's costs to provide underground service exceeds its cost to provide an overhead service.
(E) MAINTENANCE:

Maintenance will be performed by the customer.

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE NM

NET ENERGY METERING SERVICE
Sheet 1 of 3
With 2024 Excess Energy Rate
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 APPLICABILITY:

This Net Energy Metering rate schedule is applicable to all customers served by Silicon Valley Power (SVP), who own and operate a solar or a wind turbine electrical generating facility, or a hybrid system of both. Such facility shall be located on the customer's premises, shall operate in parallel with SVP's transmission and distribution facilities, shall not exceed 1000 kilowatts, and shall only be used primarily to offset part or all of the customer's own electrical requirements. Availability of this schedule to such "customer-generators" will be on a first-come first-served basis, until the total rated generating capacity operated by eligible customer-generators equals 5.0 percent of SVP's annual peak distribution demand.

RATES:

All rates charged under this schedule shall be the same as the rates charged under the eligible customer generator's otherwise applicable rate schedule (OAS). An eligible customer-generator served under this schedule shall be responsible for all charges under the otherwise applicable rate schedule, except that energy usage will be metered and billed on a net basis. An annual bill will be rendered, as required by Section 2827 of the California Public Utilities Code. A monthly statement of accumulated charges and credits shall be provided.

Monthly statements shall be subject to SVP’s payment provisions pursuant to Municipal Service Rule and Regulation No. 6, except that customers whose OAS is a demand metered SVP Rate Schedule shall be subject to monthly payment of bills, and be subject to annual true-up as necessary. If the energy generated exceeds the energy consumed during the annual billing cycle, at the customer-generator’s option, payment shall be made for such excess energy delivered to SVP's distribution facilities as set forth below, or applied as a credit to the next annual billing cycle.

LOAD AGGREGATION OPTION:

An eligible customer-generator with multiple meters may elect to aggregate the electrical load of the meters located on the property where the renewable electrical generation facility is located and on all properties adjacent or contiguous to the property on which the renewable electrical generation facility is located, if those properties are solely owned, leased, or rented by the eligible customer-generator.

If an eligible customer-generator chooses to aggregate the electrical load of such meters, (i) the eligible customer-generator shall be permanently ineligible to receive net surplus electricity compensation, and SVP shall retain any kilowatt-hours in excess of the eligible customer-generator’s aggregated electrical load generated during the 12-month period; (ii) the electricity generated by the renewable electrical generation facility shall be allocated to each of the meters in proportion to the electrical load served by those meters for each billing period. This proportionate allocation shall be calculated based on customer-generator’s load data averaged over an indicative 12-month period (estimated if necessary) and should be effective for a minimum of 12 months.

METERING:

Net energy metering is the use of a single meter to measure the flow of electricity in two directions. If the existing electrical meter of an eligible customer-generator is not capable of measuring the flow of electricity in two directions the customer-generator shall be responsible for all expenses involved in purchasing and installing a meter that is able to measure electricity flow in two directions. Any additional meter or meters to monitor the flow of electricity in each direction may be installed with the consent of the customer-generator, at SVP expense.

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE NM

NET ENERGY METERING SERVICE
Sheet 2 of 3
With 2024 Excess Energy Rate
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 SVP meter(s) to monitor the output of customer-generator’s generating facilities are required if customergenerator elects the Load Aggregation Option. Such meters shall be provided by SVP and paid for by the customer-generator.

INTERCONNECTION:

Prior to interconnection, the customer-generator shall execute an interconnection agreement with SVP and shall comply with SVP's Rules and Regulations regarding parallel generation, except that service under a standby rate schedule shall not be required. The customer-generator must also meet all applicable safety and performance standards established by the National Electrical Code, the Institute of Electrical and Electronics Engineers, and accredited testing laboratories such as Underwriters Laboratories and, where applicable, rules of the California Public Utilities Commission regarding safety and reliability.

PAYMENT RATE FOR EXCESS ENERGY:

The Payment Rate for Excess Energy shall be revised during each calendar year, and shall consist of the sum of an avoided energy cost charge and an avoided renewable energy value charge. The avoided energy cost is equal to 8000 Btu/kWh times SVP’s avoided cost of gas in $/MMBtu. The avoided cost of gas shall be the average of the 12 monthly values for PG&E Citygate taken from Natural Gas Intelligence, adjusted to include transportation to Santa Clara, ending in October of the year prior to the effective date of the Payment Rate for Excess Energy. The avoided renewable energy value charge shall be equal to the average cost of the unbundled renewable energy credits SVP purchased for SVP’s RPS compliance in the calendar year 2023.

Payment Rate for Excess Energy effective January 2024: $ 0.09294 per kWh

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE NM

NET ENERGY METERING SERVICE
Sheet 3 of 3
With 2024 Excess Energy Rate
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 Exhibit A
Rate Schedule NM
Derivation of Payment Rate for Excess Energy

1. Avoided energy cost charge:

Average of the monthly values for PG&E Citygate from Natural Gas Intelligence for the 12 months ending October 2023: $10.521 per MMBtu
Average cost of transportation from PG&E Citygate to Santa Clara Donald Von Raesfeld Power Plant for the 12 months ending October 2023: $0.330 per MMBtu
Total average delivered cost of gas: $10.851 per MMBtu
Avoided energy cost = $10.851 per MMBtu x 8000 Btu/kWh = $0.08681/kWh

2. Avoided renewable energy value charge:

The average cost of the unbundled renewable energy credits SVP purchased for SVP’s RPS compliance in the calendar year 2023: $0.00613 per kWh

3. Payment Rate for Excess Energy beginning January 2024:
$/kWh
Avoided energy cost charge $0.08681
Avoided renewable energy value charge $0.00613
Total $0.09294

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE PA-E

ELECTRIC SERVICE TO

COMMUNICATIONS ATTACHMENTS

TO SVP POLES
Sheet 1 of 2
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 APPLICABILITY:

This schedule is applicable to unmetered service to telecommunications equipment mounted on SVP-owned poles. Electric usage at each electric connection will be determined as set forth in Note (F) below.

RATES:

CUSTOMER CHARGE:

For each electric connection, per month $5.06
ENERGY CHARGE (in addition to the Customer Charge):

First 800 kWh, per kWh $ 0.24377
Excess over 800 kW, per kWh $ 0.22130
SURCHARGES:

Public Benefits Charge and State Surcharge, as set forth in Note A, will be added to the above charges.

NOTES:
(A) SURCHARGES:

PUBLIC BENEFITS CHARGE:

The Public Benefits Charge is a state required non-bypassable surcharge imposed on all sales of electricity and electrical services. It is used to fund public goods research, development, and demonstration, as well as, energy efficiency activities, renewable energy, and low income assistance programs. The surcharge is equal to 2.85% of the otherwise applicable rate.

STATE SURCHARGE: The state surcharge is required by California state law, and supports funding for the California Energy Commission. The surcharge is equal to estimated kWh per controller times the State Surcharge Rate. The current State Surcharge Rate can be found on SVP’s website at:
http://www.siliconvalleypower.com/svp-and-community/rules-and-regulations (B) TYPE OF SERVICE:

Energy will be supplied at 120 volts, single phase, two wire service. Where only other voltages are available, applicant shall pay, in advance, Silicon Valley Power's cost to convert from the available voltage to 120 volts.

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE PA-E

ELECTRIC SERVICE TO

COMMUNICATIONS ATTACHMENTS

TO SVP POLES
Sheet 2 of 2
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 (C) POINT OF DELIVERY:

Delivery will be made from Silicon Valley Power's existing electric lines at a point mutually agreed upon, without extension thereof to customer's system.
(D) SERVICE CONNECTION:

Silicon Valley Power will provide overhead or underground service in accordance with the current Rules and Regulations for Electric Service. However, applicant shall pay to Silicon Valley Power, in advance, the amount, if any, by which Silicon Valley Power's costs to provide underground service exceeds its cost to provide an overhead service.
(E) MAINTENANCE:

Maintenance will be performed by the customer.
(F) DETERMINATION OF ELECTIC USAGE:

The amount of electric usage subject to the Energy Charge shall be determined as the product of the rated capacity, expressed in kilowatts, of Customer’s communications equipment served at each connection point times 730. Customer shall be responsible for notifying SVP at least 60 days prior to making any equipment change that would increase or decrease the rated capacity of Customer’s equipment, in order that SVP may make commensurate, timely change to Customer’s billing determinants.

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE SB-1

STANDBY GENERAL SERVICE

DEMAND METERED
Sheet 1 of 2
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233

DESCRIPTION OF SERVICE
This schedule is applicable to standby service for customer’s on-site self-generation operated in parallel with service from SVP under any of SVP’s applicable demand-metered rate schedules, where such self-generation is not eligible for service under Schedule NEM. This Schedule does not apply to customer’s on-site renewable electrical generation facility where Schedule NEM is applicable. The Capacity Reservation Charges under this Schedule SB-1 are supplemental to the demand charges under the applicable demand-metered rate schedule, and are intended to result in SVP recovering its costs to provide standby services for the on-site generation capacity.

RATES:

CUSTOMER CHARGE:

The Customer Charge is equal to the applicable Customer Charge set forth in Customer’s otherwise applicable rate schedule.

CAPACITY RESERVATION CHARGE (CRC):

The Capacity Reservation Charge is equal to the applicable Demand Charge per kW set forth in customer’s otherwise applicable Rate Schedule multiplied by the lower of 45% of the nameplate rating of customer’s on-site generation or the Reservation Capacity determined pursuant to Note D.

SURCHARGES:

Public Benefits Charge, as set forth in Note B, will be added to the above charges.

NOTES:
(A) FLUCTUATIONS IN CUSTOMER’S SELF-GENERATION OUTPUT:

Customer shall coordinate with SVP’s System Dispatcher for changes of 2000 kW or more in the output of customer’s self-generation. If operationally necessary and practical, the System Dispatcher may require customer to schedule the return to service of customer’s self-generation. Such coordination shall not relieve Customers from Capacity Reservation Charges determined above. (B) PUBLIC BENEFITS CHARGE:

The Public Benefits Charge is a state required non-bypassable surcharge imposed on all sales of electricity and electrical services. It is used to fund public goods research, development, and demonstration, as well as, energy efficiency activities, renewable energy, and low-income assistance programs. The surcharge is equal to the sum of the Meter Charge and Capacity Reservation Charge, times 0.0285.
(C) PARALLEL OPERATION:

Any customer may operate its generating plant in parallel with SVP’s system if the customer’s plant is constructed and operated in accordance with SVP Rule. However, a customer who operates its plant in parallel must assume responsibility for protecting SVP and other parties from damage resulting from

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE SB-1

STANDBY GENERAL SERVICE

DEMAND METERED
Sheet 2 of 2
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 negligent operation of the customer’s facilities. Customers may be required to meet requirements imposed by other governing entities having jurisdiction over SVP’s transmission lines including the California Independent System Operator (CAISO) and the Western Electricity Coordinating Council (WECC). Customer generation under this rate schedule shall be metered by SVP. Customer shall provide a meter location that accommodates SVP’s meter and such meter shall be fully accessible by SVP. (D) RESERVATION CAPACITY:

The Reservation Capacity to be used for billing under the above rates shall be determined as set forth below:

The Reservation Capacity shall be as initially determined by SVP, except that during the first 12-month period following the date of initial determination, SVP may review the specified Reservation Capacity on a monthly basis and make adjustments as warranted (consistent with the criteria specified below).

Thereafter, SVP may perform an annual review of the most recent 12 months of actual customer operation and make prospective adjustments to the Reservation Capacity as warranted and consistent with customer’s historic operations. Any such adjusted Reservation Capacity shall be effective for a minimum of 12 months unless a documented material change of operation is provided to SVP by the customer. The customer may provide SVP with documentation of such material changes in operations as might call for an adjusted Reservation Capacity at any time. Upon receipt and review of such documentation, SVP shall revise the Reservation Capacity at its sole discretion and such a revision will be effective for the billing period immediately following receipt, acceptance and approval of the documentation and any additional information required by SVP to make such a determination. For purposes of subsequent annual reviews and any resulting adjustment to the Reservation Capacity, the following criteria shall apply:
a. For those customers who operate sufficient non-utility generating capacity so as to ordinarily satisfy all of the electric energy requirements at their site and so do not ordinarily require any service through facilities owned by SVP, the Reservation Capacity shall not exceed the customer’s highest peak demand established during the most recent 12 months of actual customer operation; b. For customers with electric loads that exceed the output capability of their non-utility generation, and thus require the regular provision of supplemental power service through facilities owned by SVP, the Reservation Capacity determination shall consider the number and size of the customer’s non-utility generating unit(s), the outage diversity of the non-utility generating units serving the customer’s load, and any reduction of customer load commensurate with non-utility generator capacity outages.

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE SL-1

STREET AND HIGHWAY LIGHTING
Sheet 1 of 4
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 APPLICATION:

This schedule is applicable for service to street and highway lighting systems which illuminate publiclydedicated streets and highways by means of incandescent filament, mercury vapor, or high pressure sodium vapor lamps. This schedule is applicable only to those instances where the customer owns the lighting fixtures, street light supporting structure and interconnecting circuits.

CLASSES OF SERVICES OFFERED:

Class A. Silicon Valley Power provides energy and switching* only.

Class B. Silicon Valley Power provides energy, switching* and maintenance service for lamps and glass.

Class C. Silicon Valley Power provides energy, switching* and maintenance service for complete lighting system.

BURNING SCHEDULE: All night (unless otherwise specified).

RATES (Per Lamp)
Half-hour
Incandescent Adjustment
Lamps kWh\lamp Class A Class B Class C (All Classes)
4,000 lumens 94 $26.93 $29.41 $30.88 $0.650
6,000 lumens 130 $38.02 $40.39 $42.16 $0.890
Mercury Vapor Lamps
Initial
Watts lumens
175 7,500 61 $20.43 $21.70 $23.71 $0.460
250 11,000 88 $28.22 $29.81 $31.88 $0.620
400 21,500 140 $42.97 $44.42 $46.42 $0.960
700 37,000 245 $71.39 $74.37 $76.46 $1.670
1,000 57,000 350 $100.99 $103.61 $105.60 $2.330
________________
* Switching Service is closed to new installations.

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE SL-1

STREET AND HIGHWAY LIGHTING
Sheet 2 of 4
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 High Pressure Sodium Vapor Lamps Half-hour
Initial Adjustment
Watts lumens kWh\lamp Class A Class B Class C (All Classes) 100 8,500 35 $10.75 $13.34 $15.31 $0.290
150 16,000 53 $20.06 $23.11 $24.66 $0.450
250 30,000 88 $31.16 $37.80 $39.78 $0.690
400 50,000 140 $45.01 $49.56 $51.61 $1.030
SURCHARGES:

The above rates include an adjustment for a Public Benefits Charge and State Surcharge as defined in Note A.

NOTES:
(A) SURCHARGES:

PUBLIC BENEFITS CHARGE:

The Public Benefits Charge is a state required non-bypassable surcharge imposed on all sales of electricity and electrical services. It is used to fund public goods research, development, and demonstration, as well as, energy efficiency activities, renewable energy, and low income assistance programs. The surcharge is equal to 2.85% of the otherwise applicable rate.

STATE SURCHARGE: The state surcharge is required by California state law, and supports funding for the California Energy Commission. The surcharge is equal to kWh billed times the State Surcharge Rate. The current State Surcharge Rate can be found on SVP’s website at:
http://www.siliconvalleypower.com/svp-and-community/rules-and-regulations (C) TYPE OF SERVICE:

This rate schedule is applicable to multiple street lighting systems. Multiple current will be supplied at nominal voltage level of 120/240 volts or 120/208 volts at the discretion of Silicon Valley Power, three-wire, single phase.
(D) ANNUAL OPERATING SCHEDULES:

The above rates for All-Night service assume 11 hours operation per night and apply to lamps which will be turned on and off once each night in accordance with a regular operating schedule agreeable to the customer but not exceeding 4,100 hours per year. (E) OPERATING SCHEDULES OTHER THAN ALL-NIGHT:

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE SL-1

STREET AND HIGHWAY LIGHTING
Sheet 3 of 4
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 Rates for regular operating schedules other than full all-night will be the All-Night rate plus or minus, respectively, the half-hour adjustment for each half-hour more or less than an average of 11 hours per night. This adjustment will apply only to lamps on regular operating schedules of not less than 1,095 hours per year, or 3 hours per night, nor more than 4,500 hours per year. (F) OVERHEAD DELIVERY POINT:

Delivery will be made from Silicon Valley Power's existing overhead lines without extension to the customer's system or at a point mutually agreed upon, not to exceed 150 feet except in special situations at Silicon Valley Power's convenience. Silicon Valley Power will provide at its expense an overhead service drop to a customer-owned inter-connected group of lamps having a connected load of not less than 2 kW. For a customer-owned inter-connected group of lamps having a connected load of less than 2 kW or individual customer electroliers with a selfcontained photo cell switch, Silicon Valley Power will connect the customer's overhead service wire to Silicon Valley Power's overhead lines at the customer's expense. (G) UNDERGROUND SERVICE:

Silicon Valley Power will provide underground service connection to a mutually agreed upon point from its overhead or underground system to one electrolier of each group of interconnected electroliers provided that the lighting system has been arranged for the least number of practical service points, there is at least 3 kW of connected load, and there are at least ten electroliers in the group. This service connection shall not exceed 25 feet from the base of the Silicon Valley Power pole in an overhead line or 40 feet of an underground line. In the event distances exceed 25 feet from a pole in an overhead system or 40 feet in an underground system, customer shall pay to Silicon Valley Power the actual expense of extending the underground feeder circuitry to the point of connection to Silicon Valley Power's overhead or underground system. In the event the customer requests service to a system of less than 10 electroliers, or less than 3 kW of connected load, customer shall install and own the extension from his system to Silicon Valley Power's distribution system and shall pay Silicon Valley Power the actual costs of connection to the system.
(H) MAINTENANCE:

Class B and C rates include all labor and material necessary for the cleaning or replacement of lamps and glassware, but is limited to glassware such as is commonly used and manufactured in reasonably large quantities. Charges will be made for lamps or glassware requiring replacement more than two (2) times in one year. Under Class C rates Silicon Valley Power will also isolate any trouble in customer's system which has resulted in outages or diminished light output. Silicon Valley Power will make necessary repairs without replacement on accessible wiring between poles and on equipment and wiring in and on poles to keep the system in operating condition. Silicon Valley Power will provide labor for the replacement of material such

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE SL-1

STREET AND HIGHWAY LIGHTING
Sheet 4 of 4
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 as ballast’s, photo-electric controls, relays, fixtures, individual poles, individual cable runs between poles where such runs are in conduit, and other individual parts of the system. The customer shall compensate Silicon Valley Power for any materials furnished. The Class C rate does not provide for any major excavation or any major replacement at Silicon Valley Power’s expense of circuits, conduits, poles or fixtures owned by the customer.

This schedule does not provide for maintenance to low pressure sodium vapor or metal halide lamps; however, at the request of the customer, Silicon Valley Power will perform any of the routine maintenance described above on a time and material cost basis provided Silicon Valley Power's regular standard maintenance equipment and procedures can be used. (I) LAMPS OTHER THAN STANDARDS:

Lamps other than the standard types and wattages referred to above may be used in Class A service only and will be billed at an average rate per watt per month of $ 0.13. LED street lighting falls in this category.

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE SL-2

PRIVATE OUTDOOR AREA

LIGHTING SERVICE
Sheet 1 of 3
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233

APPLICATION
This schedule is applicable to private all night outdoor area lighting service which illuminates privately-owned lands and property supplied from an overhead source. This schedule is applicable only to those instances where Silicon Valley Power installs, owns and maintains all facilities required to service in accordance with the Municipal Code of the City of Santa Clara and the Rules and Regulations for Electric Service. Service to lamps hereunder shall be continuous and temporary disconnection shall not be made.

BURNING SCHEDULE:

Each lamp shall be turned on and off once each night from dusk to dawn in accordance with a regular burning schedule, not to exceed forty-one hundred (4,100) hours per year.

RATES:

Rate per Lamp
Per Month
250 Watt mercury-vapor floodlight or
150 Watt high pressure sodium vapor floodlight $43.40
This rate schedule is applicable to alternating current service at a frequency of approximately 60 cycles, 120 or 240 volts, single phase. The 250 Watt mercury-vapor floodlamp type luminaire shall be mounted from a bracket attached or supported to Silicon Valley Power-owned wood poles and actuated by a photoelectric cell.

SURCHARGES:

Public Benefits Charge and State Surcharge, as defined below in Note A, is included in the above charge.

Public Benefits Charge $1.23 per Lamp
State Surcharge $0.02
Total $1.25
NOTES:
(A) SURCHARGES:

PUBLIC BENEFITS CHARGE:

The Public Benefits Charge is a state required non-bypassable surcharge imposed on all sales of electricity and electrical services. It is used to fund public goods research, development, and demonstration, as well as, energy efficiency activities, renewable energy, and low income assistance programs. The surcharge is equal to 2.85% of the otherwise applicable rate.

STATE SURCHARGE:

The state surcharge is required by California state law, and supports funding for the California Energy Commission. The surcharge is equal to estimated kWh per lamp times the State Surcharge Rate. The

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE SL-2

PRIVATE OUTDOOR AREA

LIGHTING SERVICE
Sheet 2 of 3
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 current State Surcharge Rate can be found on SVP’s website at:
http://www.siliconvalleypower.com/svp-and-community/rules-and-regulations

(B) BILLING:

Presentation of billing shall coincide with that of the customer’s primary premise account, where such account exists at the same location and no bill will be rendered for the first partial month of service. If the customer does not have a primary premise account, a monthly bill shall be prepared and presented in accordance with the rate and terms of this schedule.

No credit will be given for non-burning lamp time resulting from a fixture failure of any cause which is repaired by Silicon Valley Power in a reasonable period of time. No billing shall be apportioned among two or more customers or tenants. At the customer’s option, charges may be paid in advance. (C) CONTRACTS:

When service is requested by a tenant under this schedule, Silicon Valley Power may require the property owner(s) to enter into a contract with Silicon Valley Power concerning placement of special lighting facilities before service is established.
(D) NOTIFICATION AND REMOVAL:

The latest effective Schedule SL-2 is applicable until canceled on thirty (30) days prior written notice by the customer, or by Silicon Valley Power, at which time the light will be removed. (E) INSTALLATION - MATERIALS AND MAINTENANCE:

Silicon Valley Power will not install floodlight luminaries for private use at the rate established in this schedule on anything but Silicon Valley Power’s wood poles, supporting lines and guys existing on easement for Silicon Valley Power facilities.

Silicon Valley Power will not install any material for private use other than the floodlight, mastarm or bracket, and necessary wire, moulding and other materials necessary to connect energy to the floodlight from the secondary line. Said installation shall not exceed an extension of ten (10) feet, including the mastarm or bracket from the pole measured at right angles to the secondary line.

Upon receipt of notice from a customer of the failure of a lamp to operate as scheduled, Silicon Valley Power will, within a reasonable period of time, make the necessary repairs during normal working hours.

It shall be the responsibility of the customer to notify Silicon Valley Power of any malfunctions. (F) EXTENDING SECONDARY:

Silicon Valley Power shall extend its secondary lines one span to supply energy not to exceed 150 feet to the mercury-vapor floodlight at the basic rate in this schedule at no extra cost to the customer.

Additional extensions of secondary facilities shall be limited to three spans, but not to exceed six hundred

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE SL-2

PRIVATE OUTDOOR AREA

LIGHTING SERVICE
Sheet 3 of 3
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 (600) feet total. The cost of the material, labor and equipment for such extension shall be computed and added to the billing for the first month.
(G) RELOCATION:

Silicon Valley Power shall, upon customer’s written request, relocate its lighting facilities, provided that the customer reimburses Silicon Valley Power for all costs incurred by Silicon Valley Power to complete such relocation.

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE TC

TRAFFIC CONTROL SERVICE
Sheet 1 of 2
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 APPLICATION:

This schedule is applicable to non-metered service for traffic directional sign or signal lighting systems owned by governmental agencies and located on outdoor publicly owned street, highways and places.

RATES:

SERVICE CHARGE:

For each Standard Service Connection: $28.49 per 2 or 3-signal head per month $28.49 per pedestrian signal unit per month
Minimum Charge: $28.49 per month
For each Red LED Service Connection: $20.80 per 2 or 3-signal head per month $20.80 per pedestrian signal unit per month
Minimum Charge: $20.80 per month
For each Red and Green LED Service Connection: $15.09 per 2 or 3-signal head per month $15.09 per pedestrian signal unit per month
Minimum Charge: $15.09 per month
SURCHARGES:

Public Benefits Charge and State Surcharge, as defined below in Note A, are included in the above charges.

Standard Red LED Red + Green LED
Public Benefits Charge $0.78 $0.50 $0.44
State Surcharge $0.01 $0.01 $0.00
Total $0.79 $0.51 $0.44

NOTES:
(A) SURCHARGES:

PUBLIC BENEFITS CHARGE:

The Public Benefits Charge is a non-bypassable surcharge imposed on all sales of electricity and electrical services. It is used to fund public goods research, development, and demonstration, as well as, energy efficiency activities, and low income assistance programs. The surcharge is equal to 2.85% of the otherwise applicable rate.

STATE SURCHARGE: The state surcharge is required by California state law, and supports funding for the California Energy Commission. The amount included is equal to estimated kWh per signal head times the State Surcharge Rate. The current State Surcharge Rate can be found on SVP’s website at:

CITY OF SANTA CLARA

SILICON VALLEY POWER

RATE SCHEDULE TC

TRAFFIC CONTROL SERVICE
Sheet 2 of 2
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 http://www.siliconvalleypower.com/svp-and-community/rules-and-regulations (B) TYPE OF SERVICE:

Energy will be supplied at 120/240 volt single phase service (120/208 volts star in certain localities) unless the customer pays the additional initial cost of a 277/480 volt supply. However, service at 277/480 volts from underground systems will be made available only for new services at the option of Silicon Valley Power when this type of service is practical from Silicon Valley Power’s engineering standpoint.
(C) POINT OF DELIVERY:

Delivery will be made from Silicon Valley Power's existing electric lines at a point mutually agreed upon, without extension thereof to customer's system.
(D) SERVICE CONNECTION:

Silicon Valley Power will provide, at its expense, an overhead service drop to the customer-owned system; however, where the customer requests and underground service the customer will install and own the extension from his system to the Silicon Valley Power's nearest junction box or to the base of the pole where service is readily available and will pay the amount, if any, by which the cost of connecting to the Silicon Valley Power's distribution system exceeds the cost of an overhead service drop.
(E) METERING:

Each point of delivery will be billed separately.
(F) SWITCHING AND MAINTENANCE:

Switching and maintenance will be performed by the customer.

CITY OF SANTA CLARA

SILICON VALLEY POWER
RATE SCHEDULE TS-1

NON-METERED TRANSIT SHELTER

ADVERTISEMENT LIGHTING
Sheet 1 of 1
Date Effective: January 1, 2024 Resolution No. 23-
Supersedes Rate Effective: July 1, 2023 Resolution No. 23-9233 DESCRIPTION OF SERVICE:

This rate schedule is applicable to non-metered service provided for transit shelter advertisement lighting on public streets, highways, other public places, and private areas. Under this schedule, each transit shelter with a lighted advertisement feature shall contain no more than a single six-foot, four-lamp high-output fluorescent lighting fixture, or equivalent fixture with a wattage rating of not more than 385 watts, and shall be photosensor controlled so as to provide illumination from dusk to dawn.

RATES:

For each Transit Shelter $44.79 per fixture per month
Advertisement Lighting Fixture
SURCHARGES:

Public Benefits Charge and State Surcharge, as set forth below in Note A, is included in the above charge.

Public Benefits Charge $1.25
State Surcharge $0.02
Total $1.27
NOTES:
(A) SURCHARGES:

PUBLIC BENEFITS CHARGE:

The Public Benefits Charge is a non-bypassable surcharge imposed on all sales of electricity and electrical services. It is used to fund public goods research, development, and demonstration, as well as, energy efficiency activities, renewable energy, and low income assistance programs. The amount included is equal to 2.85% of the otherwise applicable rate.

STATE SURCHARGE: The state surcharge is required by California state law, and supports funding for the California Energy Commission. The surcharge is equal to estimated kWh per shelter times the State Surcharge Rate. The current State Surcharge Rate can be found on SVP’s website at:
http://www.siliconvalleypower.com/svp-and-community/rules-and-regulations (B) POINT OF DELIVERY:

Delivery will be made from Silicon Valley Power’s existing electric lines at a point mutually agreed upon, without extension thereof to customer’s system.
(C) MAINTENANCE:

Maintenance will be performed by the customer.

Monthly Bill Comparisons
2024 Residential Customer Change
Low User (300 kWh) Average (430 kWh) High User (1,000 kWh) Before $44.56 $64.58 $152.33Proposed $49.02 $71.03 $167.54Increase $4.46 $6.45 $15.21 2024 Commercial/Industrial Customer Change
5 Largest Business CB-6
(41,000,000 kWh)
Very Large Business CB-6
(19,500,000 kWh)
Large Industrial CB-3
(2,000,000 kWh)
Large
Commercial/Small
Industrial CB-1
(500,000 kWh)
Small Business C1
(1,000 kWh)
Before $228.75 $82,310 $302,43 $2,556,815 $5,072,590Proposed $251.60 $90,529 $332,611 $2,811,974 $5,578,861Increase $22.85 $8,219 $30,168 $255,160 $506,272 City of Santa Clara
Agenda Report
1500 Warburton Avenue
Santa Clara, CA 95050
santaclaraca.gov
@SantaClaraCity
23-1362 Agenda Date: 12/5/2023

REPORT TO COUNCIL

SUBJECT
Action on the Downtown Precise Plan, Downtown Form Based Zoning Code, Related Amendments to the General Plan, and Associated Environmental Impact Report and Mitigation Monitoring and Reporting Program

COUNCIL PILLAR
Promote and Enhance Economic, Housing and Transportation Development

BACKGROUND
Following a five plus-year community engagement process, the City has developed a Precise Plan and a Form Based (Zoning) Code to implement the City of Santa Clara’s 2010-2035 General Plan (General Plan) goals and policies to promote the redevelopment of the City’s historic downtown area (identified in the General Plan as the Downtown Focus Area). The Downtown Precise Plan (Plan) is a long-range planning document that provides detailed guidance for future land uses, urban design standards, and public right-of-way design concepts. The Plan and Form Based Code are intended to implement the General Plan’s goals and policies for the Downtown Focus Area by establishing development regulations for the Plan Area. Adoption of the Plan and Form Based Code will establish guidance and standards for new development within a portion of the Downtown Precise Plan Focus Area through policies, guidelines, and illustrations that implement the community vision and objectives for a vibrant, pedestrian-oriented destination Downtown. The Form Based Code will provide objective design standards to regulate new development projects.

The Plan and Form Based Code was presented before the Planning Commission at a publicly noticed meeting on October 25, 2023. The Planning Commission staff report (Attachment 1) provides an analysis of the project’s consistency with the General Plan, and a description of the Downtown planning process, project timeline, community engagement, and community design principles. The staff report also describes topics regarding the Plan’s implementation, including the interest of the Downtown Community Task Force (DCTF) in creating a follow-up “Community Benefits Program” after the Precise Plan adoption. The report also describes implementation challenges, including the current unfavorable economic climate, as well as ongoing challenges to build out the Plan as envisioned through the Form Based Code, due to recent State laws which override local land use authority.

At the conclusion of the public hearing, the Planning Commission unanimously voted to recommend approval of the project (6-0-1, Commissioner Bhatnagar absent).

The City Council is being asked to conduct a public hearing and take five actions related to preparation of the Plan and Form Based Code for the Downtown Focus Area:

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23-1362 Agenda Date: 12/5/2023

1. Acceptance of the Water Supply Assessment (WSA);

2. Approval and certification of the Environmental Impact Report (EIR) prepared to analyze the potential environmental impacts for the project and adoption of a Mitigation Monitoring and Reporting Program;

3. Adoption of the Precise Plan;

4. Adoption of associated General Plan text amendments to modify the Downtown Core land use designation, and amending the General Plan Land Use diagrams for Phases II and III to reflect the Downtown Precise Plan; and

5. Adoption of the Downtown zoning district into the Zoning Code.

DISCUSSION
At the October 25, 2023 Planning Commission meeting, staff presented an overview of the Downtown Precise Plan and Form Based Code and its conformance with the California Environmental Quality Act (CEQA).

Ten members of the public provided comments, including four members of the DCTF. In summary, public comments supported the importance of having Objective Design Standards, such as those provided in the Form Based Code, and to apply those standards consistently to new development.

Speakers stated that the Form Based Code is designed to provide good form, put the soul back into buildings, and to create places for people. The commercial and public spaces envisioned in these planning documents will give the community a destination, promoting walking and socializing, and the community understands that the tradeoff for achieving the vision is allowing for increased density. A University student stressed that free public spaces are important for young people and currently there is a lack of those spaces in Downtown, as well as a lack of restaurants. It was further mentioned that university students should be viewed as a catalyst for the new Downtown. Finally, the Downtown should be an iconic destination with green space, places for art and curated activities, and a place for all of Santa Clara.

Following public comments, the Planning Commission discussed the project. The Planning Commission was impressed with the amount of community involvement in the development of the Plan and the passion exhibited by the citizens in making the Plan successful. Planning Commissioners discussed the need for supercharger stations for electric vehicles, a plan and process for public art, the possibility to establish a 1% for art fee, and the desire for an iconic photo moment (e.g. an I Love Santa Clara sign). The Commission also discussed the importance of wayfinding signage, water stations, and power outlets in light poles for use during public events or by vendors. The Planning Commission then concluded discussion and adopted resolutions to unanimously recommend to the City Council approval of the project.

ALUC Review
The Plan was referred to the Airport Land Use Commission (ALUC) for review as the Plan affects property within the Airport Influence Area (AIA) of the San Jose International Airport (SJC). At the November 15, 2023 ALUC meeting, the Santa Clara County Airport Land Use Commission found the Plan to be inconsistent with the policies of San Jose Airport Comprehensive Land Use Plan (CLUP).

The eastern half of the Plan area lies within the Traffic Pattern Zone (TPZ) of SJC, while the western half of the project area does not lie within any safety zone. The entire Plan area is located outside of the noise contours of the airport area. The proposed 124-foot maximum height allowed under potential bonus heights of the Plan would conflict with the 212-foot Part 77 Surface when noting the maximum elevation of the project area is 95 feet above Mean Sea Level (MSL). This scenario would City of Santa Clara Page 2 of 5 Printed on 12/1/2023
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23-1362 Agenda Date: 12/5/2023
have a structure at the highest elevation above MSL to pierce the associated Part 77 Surface by 7 feet, leading to an inconsistency with the SJC CLUP.

In order to be consistent with the CLUP, the ALUC recommended that the following policies be added to the Precise Plan and Form Based Code that will apply to any new development on property within the Airport Influence Area (AIA).

When measuring development height for consistency with the San José International Airport (SJC) Comprehensive Land Use Plans (CLUP) Part 77 Surfaces, height is to be measured from mean sea level (MSL) to the top of the highest point of any proposed structure. Height of any proposed structure is subject to height policies set forth in the SJC and RHV CLUPs and may not exceed the Part 77 Surface immediately above that proposed structure.

All proposed development within the SJC CLUP Traffic Pattern Zone shall comply with the applicable open space requirements of the SJC CLUP (SJC CLUP policy S-5 and Table 4-2).

Where legally allowed, dedication of an avigation easement to the City of San José shall be required to be offered as a condition of approval on all projects located within the Airport Influence Area.

The proposed policy recommendations are acceptable in that they are standard practices the City follows within the Airport Influence Area and the recommended policies have been added to the Downtown Precise Plan.

ENVIRONMENTAL REVIEW
The action being considered takes into account the potential environmental impacts of the project through the preparation of an Environmental Impact Report for the project. The EIR was prepared in accordance with the California Environmental Quality Act and circulated for a 45-day public review between May 31, 2023 and July 17, 2023. A total of three comments were received during the comment period. Two were from local/regional agencies, Valley Water and the Santa Clara Valley Transportation Authority. The third letter received was from an organization, the Judicial Council of California. None of the comment letters identified a new significant impact or have provided substantial evidence that the CEQA analysis is otherwise inadequate. Recirculation of the EIR is therefore not required. Responses to the Draft EIR comments, as well as minor text changes and clarifications, in the form of a Final EIR, were made available to the public through the City’s website on October 11, 2023, and have been forwarded on to any commenters on the Draft EIR. A website link to the Final EIR, Mitigation Monitoring and Reporting Program (MMRP), CEQA Findings, Statement of Overriding Considerations and Response to Comments is provided in Attachment 2 to this report.

The EIR identified potential environmental impacts associated with the project and identified air quality, biological, cultural resources, geology and soils, hazards and hazardous materials, noise, and tribal cultural resources as having impacts that with the incorporation of mitigation measures would be reduced to less than significant. The EIR also identified Greenhouse Gas Emissions as having a significant unavoidable impact with mitigation incorporated and Land Use and Planning as having a significant unavoidable impact.

For Greenhouse Gas Emissions, the EIR identifies that the Plan is not fully consistent with the City of Santa Clara Page 3 of 5 Printed on 12/1/2023
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23-1362 Agenda Date: 12/5/2023
development assumptions of the 2022 Climate Action Plan (CAP), in that only a portion of the Plan’s development capacity was accounted for in the 2022 CAP assumptions. As such, projects approved prior to January 1, 2031 would be required to demonstrate conformance with the 2022 CAP measures and projects approved after December 31, 2030 would not be covered by the 2022 CAP and will be required to implement Mitigation Measures GHG-1.1 and GHG-1.2 as outlined in the EIR.

For Land Use and Planning, the EIR identifies that even with implementation of the Greenhouse Gas Emissions Mitigation Measures GHG1.1 and GHG-1.2, projects initiated after 2030 could conflict or otherwise interfere with the statewide GHG reduction measures set forth by SB 375. As a result, implementation of the Plan would result in a significant unavoidable land use impact.

Water Supply Assessment
City staff prepared a Water Supply Assessment for the Plan, which is in Appendix E of the EIR. An Assessment is required to analyze the utility’s current and future water supplies as well as the current and projected water demands in the utility’s service area. The Assessment must include a determination as to whether additional water supplies are necessary or if sufficient water supplies exist for the proposed development. The law also requires that the water utility’s governing body approve water supply assessments. The City Council is the governing body for the City’s Water Utility.

The Assessment provides a detailed analysis of the amount of water necessary to meet the needs of the proposed development and the City’s ability to supply that amount of water based on the projections identified in the City’s Urban Water Management Plan as well as water supply assessments prepared after the City’s Urban Water Management Plan was approved in 2020. The Assessment found that the City’s water utility has sufficient water supplies to meet the projected water demand of this development during normal, single dry year, and multiple dry year scenarios.

Council’s approval of the Assessment (see attached resolution, Attachment 3) is necessary for the Plan to be approved.

Conclusion
A detailed discussion of the potential impacts and mitigation measures to be applied are specified in the EIR and would be implemented through project conditions of approval and the MMRP for the proposed project.

FISCAL IMPACT
There is no fiscal impact to the City other than administrative staff time and expense to prepare this report.

COORDINATION
This report has been coordinated with the City Attorney’s Office.

PUBLIC CONTACT
Public contact was made by posting the Council agenda on the City’s official-notice bulletin board outside City Hall Council Chambers. A complete agenda packet is available on the City’s website and in the City Clerk’s Office at least 72 hours prior to a Regular Meeting and 24 hours prior to a Special Meeting. A hard copy of any agenda report may be requested by contacting the City Clerk’s Office at (408) 615-2220, email [email protected] <mailto:[email protected]> or at the public information desk at any City of Santa Clara public library.

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23-1362 Agenda Date: 12/5/2023
On October 11, 2023, a notice of public hearing of this item was posted in three conspicuous locations within 1,000 feet of the project site. A notice of public hearing was also published in the Weekly, a newspaper of general circulation in the City, on October 11, 2023. As of the time of this report, the Community Development Department has not received any comments. However, public input has been received and considered throughout the planning process and is described in more detail in the Planning Commission staff report (Attachment 1).

ALTERNATIVES

1. Provide alternate direction regarding adoption of a resolution approving the Downtown Precise Plan Water Supply Assessment.

2. Provide alternate direction regarding the adoption of a resolution approving and certifying the Final EIR prepared for the Santa Clara Downtown Precise Plan (SCH # 2022010282), including CEQA Findings and a Statement of Overriding Considerations.

3. Provide alternate direction regarding the adoption of a resolution approving the Downtown Precise Plan.

4. Provide alternate direction regarding the adoption of a resolution approving a General Plan text amendment to modify the Downtown Core land use designation, and amending the General Plan Land Use diagrams for Phases II and III to reflect the Downtown Precise Plan.

5. Provide alternate direction regarding the adoption of an ordinance amending the zoning code to create the Downtown Zoning district.

RECOMMENDATION
Alternative:

1. Adopt a resolution approving the Downtown Precise Plan Water Supply Assessment.

2. Adopt a resolution approving and certifying the Final EIR prepared for the Downtown Precise Plan and Form Based Code (SCH # 2022010282), including CEQA Findings and a Statement of Overriding Considerations, and adopting the project’s Mitigation Monitoring and Reporting Program.

3. Adopt a resolution approving the Downtown Precise Plan.

4. Adopt a resolution approving a General Plan text amendment to modify the Downtown Core land use designation and amending the General Plan Land Use diagrams for Phases II and III to reflect the Downtown Precise Plan.

5. Waive first reading and introduce an ordinance amending the zoning code to create the Downtown Zoning district and make corresponding changes to the zoning map.

Reviewed by: Andrew Crabtree, Director, Community Development Approved by: Jovan Grogan, City Manager

ATTACHMENTS

1. Planning Commission Staff Report of October 25, 2023

2. Web Links to the Precise Plan, Form Base Zoning Code, Environmental Impact Report, CEQA Findings, Statement of Overriding Considerations, Downtown website

3. Water Supply Assessment Resolution

4. Final EIR Resolution

5. Downtown Precise Plan Resolution

6. General Plan Amendment Resolution

7. Form Based Zoning Code Ordinance
City of Santa Clara Page 5 of 5 Printed on 12/1/2023
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City of Santa Clara
Agenda Report
1500 Warburton Avenue
Santa Clara, CA 95050
santaclaraca.gov
@SantaClaraCity
23-1115 Agenda Date: 10/25/2023

REPORT TO PLANNING COMMISSION

SUBJECT
Action on the Downtown Precise Plan, Downtown Form Based Zoning Code, Related Amendments to the General Plan, and Associated Environmental Impact Report and Mitigation Monitoring and Reporting Program.

COUNCIL PILLAR
Promote and Enhance Economic, Housing and Transportation Development

EXECUTIVE SUMMARY
Following a five plus-year community engagement process, the City has developed a Precise Plan and a Form Based (Zoning) Code to implement the City of Santa Clara’s 2010-2035 General Plan goals and policies for the Downtown Focus Area to promote the redevelopment of the City’s historic downtown area. The Downtown Precise Plan is a long-range planning document that provides detailed guidance for future land uses, urban design standards, and public right-of-way design concepts. The Precise Plan and Form Based Code are intended to implement the General Plan’s goals and policies for the Downtown Focus Area by establishing development regulations for the Plan Area. Adoption of the Precise Plan and Form Based Zoning Code will establish guidance and standards for new development within a portion of the Downtown Precise Plan Focus Area through policies, guidelines, and illustrations that implement the community vision and objectives for a vibrant, pedestrian-oriented destination Downtown. The Form Based Code will provide objective design standards to regulate new development projects.

Precise Plans, Form Based Codes and other focused land use regulations outline specific criteria for development in a designated area and are intended to convey a community’s desire for how development should occur. Such regulations are tools that articulate clear (“objective”) standards, with the hope that property owners, investors, and developers will align to those standards. As a benefit to aligning to the community’s objective standards, the approval process for projects that are consistent with those standards is streamlined and generally avoid lengthy local/city processes for exceptions and code amendments. However, over the last 5-10 years, the State of California has adopted housing laws that bypass local approval processes. The stated intent for many of these laws are to: (1) increase the production of housing, (2) reduce barriers imposed by local agencies, (3) increase affordability, and (4) reduce processing times for planning entitlements and building permits.

Due to the myriad of State laws that allow local land use rules to be waived, local policy makers often balance community desires to impose regulations on development, with the alternatives provided by State housing laws. If local regulations are viewed as being too stringent, developers/property owners may seek to utilize State laws to waive local rules, thus limiting the effectiveness of tools such as precise plans and form based codes.

Through this report, its attachments, and the presentation(s) at the October 25, 2023 meeting, the City of Santa Clara Page 1 of 15 Printed on 10/23/2023
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23-1115 Agenda Date: 10/25/2023
Planning Commission is being asked to conduct a public hearing and make recommendations on three actions for City Council consideration related to the adoption of a Downtown Precise Plan and Form Based Zoning Code for the City of Santa Clara:
1) Recommendation on the adequacy of the Environmental Impact Report (EIR) prepared to analyze the potential environmental impacts for the project and an associated Mitigation Monitoring and Reporting Program, set of CEQA Findings and a Statement of Overriding Considerations;
2) Recommendation to the City Council on the adoption of the Downtown Precise Plan and Related General Plan Amendments; and
3) Recommendation to the City Council on the adoption of an ordinance amending the zoning code to create the Downtown Form Based Zoning district.

BACKGROUND
The City of Santa Clara’s 2010-2035 General Plan identifies focus areas for the City’s growth throughout the City, including the Downtown area, to promote the City’s diverse economic base and meet the demand for housing that addresses job growth in the City and region.

Downtown Planning Process
While the City has made previous attempts to plan for and redevelop its historic Downtown, efforts began anew after the adoption of the 2010 General Plan when in August 2015 the City Council adopted a Strategic Objective to evaluate a Santa Clara Downtown/Super Block project. The City then hired an urban design consultant to help facilitate a series of community workshops and meetings which took place between October 2015 and November 2017, and were used to gather input on a vision for the Downtown area’s future development. Through this process, the community identified several objectives for the redevelopment of the Downtown area as a vibrant, pedestrianoriented destination, including, as a primary objective, the restoration of Franklin Street as a public right-of-way open to vehicular traffic. These objectives were subsequently used as an input into a more rigorous planning effort which began in 2019.

The possibility of revitalizing the City’s historic Downtown area energized City community members, including organizations such as Reclaiming Our Downtown (ROD) and the Old Quad Resident’s Association (OQRA). In 2018, ROD began actively lobbying the City for a restoration of the City’s historic downtown, and in particular the development of a theater. The community’s interest in the preparation of a plan for near-term redevelopment and revitalization of the downtown grew to include other community members. In response to this community interest, the City Council included $578,346 to support the preparation of a Downtown Precise Plan in the City’s FY 2018/19 and 2019/20 Adopted Capital Improvement Program Budget. The Downtown Precise Plan was intended to provide guidance for new development within the Downtown area through policies, guidelines, and illustrations intended to implement the community’s vision and objectives for a vibrant, pedestrianoriented downtown destination. Following approval of this funding, the City issued a Request for Qualifications (RFQ) for consultant services to support the initiation of the Precise Plan preparation process. In October 2019, the City entered into an agreement with the selected consultant, WRT, for preparation of the Precise Plan. In June 2020, the agreement was amended to add $100,000 for the study of additional land use options and their financial feasibility and additional meetings with stakeholders and the Task Force.

A Downtown Community Task Force (DCTF) was appointed by the City Council to provide input on City of Santa Clara Page 2 of 15 Printed on 10/23/2023
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23-1115 Agenda Date: 10/25/2023
the Plan throughout the planning process. The members of the DCTF include representation from a diverse range of backgrounds and perspectives including the OQRA, ROD, Santa Clara University, the Historical and Landmarks Commission, and the Cultural Commission. The DCTF is an advisory body that met over the course of the Downtown Precise Plan planning process. The purpose and mission of the Task Force was to provide input and help guide the Downtown Precise Plan planning process through:
§ High-level strategic thinking on the direction of the plan at key points in the project; § Review, interpretation, and guidance on the results of the public workshops and other engagement activities; and
§ Recommendations on the vision, land use, circulation, and key policy topics for the project area.

As the planning process progressed, the DCTF proactively contemplated the next steps towards implementation of the Precise Plan with the goal of making sure that those steps lead to the best possible outcomes for a successful downtown. Accordingly, the DCTF requested the City Council to add the preparation of a Form Based Zoning Code for Downtown to the consultant scope of services.

Form Based Codes are an alternative approach to zoning standards that are particularly applied to areas where a pedestrian-oriented environment and more traditional “Main Street” type of development is a priority. Form Based Codes may omit much of the land use regulations found in conventional zoning codes, thereby allowing for a mix of uses (e.g., residential above commercial) that would have been seen in a traditional Downtown environment, while also establishing very precise regulations for architectural form, such as specifications for minimum and maximum setbacks, location and size of building entries, allowable building materials and other architectural elements critical to the creation of a successful pedestrian environment.

In May 2021 the City Council approved a contract amendment to add the Form Based Zoning Code task to the consultant scope of work and planning process and added funding of $300,000 for this additional work from the General Fund Capital Projects Reserve to cover the total cost of the amendment to the Agreement. This amendment brought the total to $978,346 for the development of the Precise Plan and Form Based Code.

A consultant team headed by WRT was engaged to support the City in the preparation of the Downtown Precise Plan and the Form Based Zoning Code. The planning process started with an existing conditions analysis, followed by various forms of community outreach, further detailed in the community outreach section of this report below, to receive community input on visioning, land use, circulation, and design standards. Staff and the consultant team met with a developer stakeholder group and conducted an independent analysis to establish a framework for economic feasibility to inform the planning process with the intent that the Plan would support an adequate amount of new development capacity to promote near-term redevelopment. The process was further layered with review and input from the Downtown Community Task Force (DCTF), as well as internal City departments.

Project Timeline
The following are key milestones in the Precise Plan and Form Based Code planning process:
§ October 2019: Consultant (WRT)/City Project Kick-Off Meeting § May 2021: Added Tasks & Budget to Scope (Form Based Code - Sargent Town Planning) § June 2021: Downtown Community Task Force (DCTF) Confirmed the Draft Land Use/Height City of Santa Clara Page 3 of 15 Printed on 10/23/2023
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Plan Framework
§ September 2021: City Council Confirmed Draft Land Use/Height Plan Framework § October 2021: Community Outreach Complete
§ May 2022: Draft Plan Complete (Revised Draft Completed 11-18-22) § June 2022: Draft Form Based Code Complete (Revised Draft Completed 11-17-22) § November 2022: Community Open House - Presentation of Precise Plan & Form Based Code § May 31, 2023 - July 14, 2023: Environmental Impact Report (EIR) Circulation § August 2023: Adoption Draft Precise Plan and Form Based Code Complete § December 2018 through September 2023: Downtown Community Task Force (DCTF) Meetings - 42 Meetings
Preparation of the items now under consideration by the Planning Commission are the result of a nearly four-year community-based planning effort. This process has been largely focused on an appointed Downtown Community Task Force (DCTF) which has thoroughly reviewed all aspects of the proposed Precise Plan and Form-Based Code. The Planning effort began in late 2019 with conventional forms of community engagement (e.g., community meetings, workshops, “pop-up” activities at community events), and then transitioned in 2020, after approximately a six-month delay, to multiple forms of on-line engagement. In-person meetings resumed in early 2023 following the end of the Covid-19 emergency declaration. DCTF meetings have been held once or twice a month with a few breaks since September 2020 until the present time, with the most recent DCTF meeting held on Thursday, October 19, 2023. Agendas and materials for these 43 DCTF meetings are available on the City’s website. All of the DCTF meetings were open to the public and included participation by other community members. Broader community engagement took place through general community meetings, on-line surveys, workshops and other activities conducted at key stages in the planning process.

Community Engagement
Over the course of the Downtown Precise Plan planning process, the planning team has received feedback from community members and stakeholders in the following ways:
§ 43 Downtown Community Task Force (DCTF) meetings. Details of each meeting, including meeting materials and videos recordings can be found under the Task Force page of the Downtown Precise Plan website.
§ Two online Survey’s on the topics of Land Use Concepts during May 2020 and Placemaking during October 2021.
§ Two “Meeting in a Box” activities distributed to the community in January/February 2020 and June 2020. (“Meeting in a Box” provided community members with a set of community engagement tools that they could use to lead multiple small groups of community members through in person and on-line planning activities to inform preparation of the Precise Plan.) § Downtown Retail 101 Community Workshop on January 16, 2020. § A lunchtime student engagement workshop at Santa Clara University on January 29, 2020. § Meetings with stakeholders and technical advisors from January through March 2020. § Placemaking Community Workshop on October 12, 2021.
§ Community Open House on November 19, 2022.

Summaries and meeting materials for all community engagement activities can be found on the Downtown Precise Plan website under community engagement reports at:
www.santaclaraca.gov/downtown
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Community Design Principles
During the initial year of the planning process, beginning in December 2019, the City and the DCTF solicited community input and crafted and refined a preferred land use “framework plan” for achieving the community vision for Downtown. This is presented in the Precise Plan as an overall Vision for the Downtown that it be “Authentic Adaptable, and Affordable”. In this context, “Authentic” indicates that the Downtown should have a variety of forms that appear to have developed over-time and with multiple architectural styles, similar to the urban form of a traditional downtown. “Adaptable” indicates that the Precise Plan should be able to support development in a variety of economic conditions and accommodate changing social trends. “Affordable” indicates that the retail and the housing found within the Downtown will be at prices accessible to people at a variety of income levels. Collectively these elements suggest that the Downtown will be potential home to and an attractive destination for a wide variety of people from Santa Clara and surrounding communities.

The vision for the design of Downtown is further articulated under two headings, “community priorities for streets and public spaces”, and “urban form”. The vision emphasizes a restored street grid, open spaces for community gathering, human scale and pedestrian comfort, building height variation and a diversity of uses in the following text.

The Precise Plan seeks to achieve the following community priorities for streets and public spaces:
§ A restored street grid;
§ Multi-modal streets;
§ Active and pedestrian-scaled Franklin Street;
§ Parks and plazas for community gathering and community programs; § Outdoor seating.

The urban form of Downtown should be characterized by:
§ Human scale and pedestrian comfort (The Precise Plan and Form-based Code are intended to provide “Human Scale” architectural elements that reduce the perceived building mass to a comfortable level and provide visual interest as experienced by pedestrians on the street and roadway design that does not give automobile traffic priority over pedestrian comfort.); § Building height variation and diversity;
§ Buildings massing that supports urban life and steps down to the neighborhood context; § Integration of traditional and contemporary building forms sensitive to nearby historic homes; § A mix of building uses, including retail, cultural catalysts, housing and offices.

DISCUSSION
The primary issues for the Planning Commission to consider in evaluating the proposed Precise Plan and Form Based Code are consistency with the General Plan and the strength of the Plan’s policies and standards to implement the Plan vision. The Planning Commission, and subsequently the City Council, have the opportunity to review these policies and standards and identify areas where they may be enhanced, modified or further developed to address City objectives and priorities.

Additionally, both bodies should consider the new regulations in the context of State laws that allow local land use rules to be waived. As noted above, if local regulations are viewed as being too stringent, developers/property owners may seek to utilize State laws to waive local rules, thus limiting the effectiveness of tools such as precise plans and form based codes. Input and recommendations from the Planning Commission will be forwarded to the City Council for their consideration; direction from the City Council will be incorporated into the final, adopted version of the Precise Plan and Form Based Code.

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General Plan Consistency
The Project is located within the Downtown Focus Area. Focus Areas identified in the 2010-2035 General Plan represent locations with opportunities for more intense development with limited impact on existing neighborhoods. The Downtown Focus Area provides direction through the following goals for achieving a unique destination in the City to serve both local and regional interests.

5.4.2 ‐
G1 A Downtown that serves as a primary, pedestrian
‐
oriented commercial and cultural
destination.

5.4.2 ‐
G2 New Downtown development that is integrated with older existing development with respect to intensity, scale and character.

5.4.2 ‐
G3 Higher
‐
intensity development that is concentrated in the area designated as Downtown Core (located in the eastern portion of the Focus Area).

5.4.2 ‐
G4 Pedestrian and transit priority for mobility in the Downtown Focus Area.

The Precise Plan is consistent with these goals and provides much more detail, and direction on public streets and spaces, essential land uses, urban form, and development capacity.

First, the Plan provides direction on re-establishing the street grid for Downtown, and direction on how each street shall be designed to achieve the desired character and complement adjacent land uses and desired activities. For example, Franklin Street is designated as a pedestrian oriented street with wide sidewalks giving pedestrians the priority, a travel lane in either direction and a multiuse curb lane can be used for a variety of uses that are likely to change over time as the area changes, such as drop-off zones, delivery zones, bike share stations and on-street parking. This configuration differs from Benton Street which is designated as a community connector street that will have traffic and bicycle lanes in each direction separated by a center turn lane and on-street parking with standard sidewalks.

Second, the Plan builds up from the street grid by designating the location of publicly accessible open spaces and retail spaces, as well as retail ready spaces (spaces designed to be able to accept retail uses in the future when there is sufficient demand). The public spaces are linked together along Franklin Street and serve different purposes for Downtown, but all are to be visible from streets, welllit, and address utilitarian demands while providing space and infrastructure for events and programs.

Third, the Plan provides standards for building form through the establishment of maximum building heights. Parcel-by-parcel, low-intensity land uses will be replaced by development projects that deliver housing and office space in taller buildings with context-appropriate building heights and massing. Proposed building heights will step down in height where the Downtown area abuts existing residential neighborhoods, while stepping up in height along the east end of the Downtown’s central spine, Franklin Street. The Plan envisions that amenities will be most abundant along Franklin Street and at the Main and Franklin Street crossing, marking the Downtown’s “civic axis” leading to City Plaza Park.

Additionally, the Precise Plan boundary generally aligns with the boundary depicted in for the Downtown Focus Area in the General Plan with the exception of the westernmost area along Franklin Street between Madison and Lincoln Streets. This area, which is included in the Focus Area, does not encompass a full block and only incudes narrow/shallow parcels fronting on Franklin Street, of City of Santa Clara Page 6 of 15 Printed on 10/23/2023
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which a majority are single-family residences and thereby determined to be not conducive to redevelopment.

Finally, the current General Plan Downtown Focus Area development capacity, corresponding to areas designated as High Density Residential, Community Mixed Use, and Downtown Core, is estimated to be 396 housing units and 130,000 square feet of non-residential development, not including civic uses. The proposed Precise Plan allows for a greater intensity of development with a capacity of up to 1,071 residential units, 531,720 square feet of office space, 197,900 square feet of commercial/retail space, and 44,300 square feet of public space.

Precise Plan
The proposed Precise Plan includes several chapters: Development Framework; Streets and Public Spaces; Ground Floor Uses; Urban Form; Historic Resources; and Implementation.

Development Framework
The Framework provides general guidance for the types of land uses and amount of development allowed within the Precise Plan. The Framework supports an approach to redevelopment that integrates the community’s vision and priorities with the goal of providing sufficient flexibility for the redevelopment of the Downtown to be economically achievable.

A market study was conducted in 2020 to analyze the economic conditions and financial feasibility for the implementation of the Precise Plan. Based on this analysis, the City’s consultant provided recommendations for types and densities of development that would be feasible within the Downtown context. This analysis was presented to the DCTF at DCTF Meeting #6 on March 9, 2020 and is included within the Draft Plan (Attachment #1 Precise Plan, pp 18-20; p. 22). This analysis indicates that feasible forms of development include residential townhouses (30 dwelling units / acre), residential condominiums (at 70 dwelling units per acre or higher), residential rental apartments (at 80 dwelling units per acre or higher), office (Downtown office at a Floor Area Ratio of 5.0). The consultant’s analysis further states that these types of development may be feasible at slightly lower densities. The feasibility analysis for ground floor retail, which is required at some locations in the Precise Plan, indicates that it would be revenue neutral, neither adding to nor detracting from the overall feasibility of mixed-use development.

Market feasibility analyses are based upon a single point in time, but also take longer term trends into consideration. Since the analysis was completed in 2020, market conditions have changed in several ways, two of which are significant considerations for the Downtown. First, speculative office development has dropped significantly as developers remain unsure about the future demand for office space with increased telecommuting still a significant factor. While long-term trends suggest that the Silicon Valley will remain a strong economic driver so that office demand will return, it is unclear what the timing for that return will be. After an initial pause in 2020, demand for residential development has remained strong since 2020 until interest rates rose dramatically earlier this year.

For residential development, the current combination of high interest rates, a lack of interested investors, stable or declining apartment rents, and high construction costs has cooled new marketrate apartment development projects. Townhouse and affordable housing development remains feasible in the current market conditions. Changes in external market conditions could easily return apartment development to feasibility or have other effects. To address these uncertain market conditions, the Precise Plan is intended to provide flexibility for land uses, a range of densities consistent with likely market demand, and land use policies that can be implemented over several City of Santa Clara Page 7 of 15 Printed on 10/23/2023
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years as market conditions vary.

To provide flexibility in land development while supporting a traditional downtown form, the Framework focuses upon building form and height in place of a typical land use plan with various colors designating areas for different land uses. The maximum allowed building heights range from two stories to seven stories. Buildings may be used for housing, offices, hotels, civic or cultural uses, or a mix of these uses. The ultimate development capacity for the Precise Plan was determined based upon building heights and the expected capacity for various land uses within those building heights.

In addition to an overall building form diagram, the Framework is accompanied by diagrams for Streets and Public Spaces, Ground Floor Uses, and Urban Form that collectively support the Precise Plan goals and policies, design standards and guidelines, and implementation measures.

Streets and Public Spaces
This chapter provides direction for the re-establishment of the street grid, and the design of a hierarchical street network by providing cross sections for four street types: Major Thoroughfare, Community Connectors, Pedestrian Oriented, and Service Oriented, described in more detail below.

The cross section for each street type includes a total right-of-way width and a dimensioned depiction of the elements that are to be included within that right-of-way. The Precise Plan prioritizes bikefriendly designs for the new or modified streets within the Downtown by maintaining bike lanes on Monroe Street, Benton Streets, and Homestead Road, and calling for a new continuous bicycle route on Washington Street, where bikes and slow-moving vehicles can share lanes. The four street types are described as follows:

Major Thoroughfare - 10-foot sidewalk, 5-foot landscape strip, street parking, travel lane in either direction, and a center turn lane
Community Connectors - 11-foot sidewalk, 7-8-foot multi use lane (landscape bulb out and/or street parking), 5-foot bike lane, travel lane in either direction, and a center turn lane Pedestrian Oriented - 10-foot sidewalk, 7-foot multi use lane (landscape bulb out, street parking, drop-off zones, service and delivery zones, bike share stations), travel lane in either direction shared by bikes and cars
Service Oriented - 18-foot sidewalk with a 5-foot landscape strip down the center and against the curb, 7-foot multi use lane (landscape bulb out, street parking, drop-off zones, service and delivery zones), and a travel lane in either direction shared by bikes and cars To make Downtown a vibrant place and attractive destination, the Plan includes policies for the creation of public spaces including, parks, plazas, paseos, and other publicly accessible spaces.

These spaces should be flexible, while also providing amenities and public art. There are three required plaza and park locations indicated in the Plan, strategically placed along Franklin Street, with unique features distinguishing each space as described below:

Arts Commons, a “town square” near where Franklin Street and Lafayette Street will intersect, where City-owned land can be leveraged to create a flexible, amenity-rich plaza to accommodate public gatherings and events, such as viewing outdoor films.

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Central Green, a common open area located on the four corners at the intersection of Franklin and Main Streets, to activate and visually unify the four corners with multi use lawns and trees.

Franklin Plaza, a small plaza located in front of and north of the historic Post Office, sufficient in size to host Downtown’s weekly farmers market when combined with adjacent streets that can be temporarily closed.

Ground Floor Uses
Franklin Street is planned to be a continuously lively and welcoming centerpiece for Downtown with active uses and attractive shopfront architecture. As such, this Chapter provides detail on where ground floor retail and “retail-ready” ground floor spaces are required. “Retail-ready” spaces are ground floor spaces which will have shopfront architecture and appropriate building infrastructure to support future retail use, but the use need not be retail at the outset. These spaces can be converted to retail uses as market demand allows.

Urban Form
This Chapter provides more detailed guidance on how the intensified massing of new development will be designed to be compatible with the existing Downtown context. Per the Urban Form standards, new building heights and forms will be sensitively and specifically designed to respond to the context of the conditions along and within the Precise Plan boundary. Building heights will step down in the north along the Benton Street boundary and to the southwestern boundary along Homestead Road to provide a transition down to the neighborhood scale. More intense mass and density are allowed in a concentrated area at the central civic axes of Main and Franklin Streets and at the east end around the Arts Commons at Lafayette Street. Finally, building heights will also step down to respond to the scale of historic structures at the west end of the Precise Plan area including the post office and historic homes located in the blocks between Monroe and Madison Streets.

The density allowed in the Plan is of a sufficient height and intensity to support new residential and employment development within the Downtown thereby increasing patrons, foot traffic, and market support for Downtown retail, restaurants, and services. Prohibiting auto oriented and other low intensity uses will further leverage the Downtown’s potential for activation. Allowing greater building heights within the Downtown will also reduce the community’s overall environmental footprint, as focusing growth into mixed-use, walkable districts generates less traffic and greenhouse gas per capita than more car-reliant districts. To promote this type of walkable environment, new development will be required to achieve a minimum density of 35 units per acre cumulatively within the Precise Plan area. The overall density will be monitored, and new development will be required to maintain this overall minimum threshold for cumulative density or intensity of development.

Historic Resources
This Chapter identifies the historic resources in the Precise Plan area and provides policies as to their preservation and reuse. The Post Office is designated as a building of notable character and five properties within the blocks west of Monroe are designated as historic resources on the City’s Historic Resources Inventory (HRI). The Precise Plan provides direction to conserve historic resources to promote a sense of history, while allowing building use to change over time. Additionally, the Precise Plan requires new development to be designed to be compatible with the historic resources, consistent with the Secretary of the Interior Standards and City regulations, by designing with similar proportion, scale, facade modulation, and step downs.

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Implementation
The vision for Downtown presented in the Precise Plan will require implementation actions by the City, other Downtown property owners, arts and cultural organizations, business owners, and residents, over many years.

The Precise Plan is intended to provide land use policies that provide both sufficient flexibility and sufficient direction so that the Downtown vision can be successfully realized piece by piece over time.

The Precise Plan includes a brief summary of potential opportunities and challenges for implementation (Attachment 1 Precise Plan p. 22). Implementation Measures are provided throughout the Precise Plan and collectively presented in the Implementation Chapter, which provides a table to summarizes these implementation measures needed to achieve the outcomes described in the Precise Plan (Attachment 1 Precise Plan p. 110.

Uncertain economic conditions and a growing number of State laws that override local land use authority both present potential challenges to the realization of Precise Plan vision. Changing economic conditions are not a new phenomena and planners have learned that both a clear vision and flexibility are important for a plan to stand up over time so that it is ready to be implemented when favorable economic conditions are present. At the same time, developers are increasingly provided through State legislation with the means to bypass local regulations when those are perceived as too onerous. At present, taking advantage of State legislation generally requires a slightly higher level of affordable housing to be incorporated into a project than otherwise required by the City, and in some cases may require use of more expensive labor. These add some additional costs for the developer, but if the Precise Plan is too restrictive in terms of height or density, a developer may choose to take on those costs in order to achieve an economically viable development project. Given that new legislation intending to promote housing production is adopted each year at the State level, it is quite possible that future legislation will further undermine the City’s land use authority.

The City owns approximately six acres within the Downtown area (primarily Blocks A and B; see Attachment 1 Precise Plan p. 37) that could be made available for development in the near-term to help implement the Precise Plan and serve as a catalyst for advancing the overall objective to reestablish the Downtown. However, the City is also subject to State regulation of the surplus land process that could be an obstacle to realization of the Precise Plan and Form-based Code. For example, the State process prioritizes sale to affordable housing developers over market rate developers and it should be noted that affordable housing developers have the ability to waive elements of both the Precise Plan and Form-based Code. The City also owns the parking that supports the Franklin Mall area, but with a large number of other property owners, the Precise Plan does not anticipate the redevelopment of Franklin Mall (Blocks H and G) in the near term, but considers the continued presence of Franklin Mall as compatible with the planned redevelopment of other blocks. Other properties within the Precise Plan area are likely not available for development in the near future. These include Blocks C and E, which currently are developed with a high-value residential use, and Block D, which is partially owned by the State Court system and partially encumbered with an obligation to provide parking for the courthouse. These challenges were extensively discussed through the planning effort and are addressed within the Precise Plan, with a recognition that the Precise Plan will need to be both a flexible and in some cases a long-term plan.

Form Based Code - Downtown Zoning District
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While the Precise Plan describes the vision for a revitalized Downtown and policies and implementation measures to achieve that vision, the Form Based Zoning Code (Code) will be the primary implementation tool to realize this vision by providing detailed development standards for all new private and public improvements within the Downtown Precise Plan boundaries. A form-based zoning code differs from a traditional zoning code by focusing on form rather than land use.

Accordingly, the proposed Code will establish very precise regulations for architectural form, such as detailed specifications for minimum and maximum setbacks, location and size of building entries, allowable building materials and other architectural elements critical to the creation of a successful pedestrian environment.

Character Overlays
To achieve the vision of the Precise Plan the Code includes four Character Overlays, (1) Shopfront Overlay, (2) Retail-Ready Overlay, (3) General Overlay, and (4) Neighborhood Edge Overlay. The intent of these overlays is to calibrate the standards and guidelines of the Code to the desired character for these specific urban environments as envisioned in the Precise Plan. This includes standards intended to concentrate street life at key locations within the center of Downtown while regulating the form of development to provide a smooth transition to the existing neighborhood context at the edges of Downtown.

Development Standards and Guidelines
The standards and guidelines of this Code are both “place-based” and “form-based,” with all standards and guidelines mirroring the public realm plan in the Precise Plan. The Code assigns specific building height standards, building setback standards, building use standards, and building form and design standards and guidelines on a street-by-street and block-by-block basis to systematically, cohesively and predictably implement the community’s vision. The Code also prescribes the permitting processes for new development within the Precise Plan boundary. Design standards will be established through the Code for the following:
§ Building placement, height, massing, and width
§ Building facades, scale, and character
§ Vertical organization of doors and windows
§ Building frontage design at the public realm
§ Architectural projections
§ Privacy
§ Retail design
§ Signage
The proposed Precise Plan establishes specific limitations on height throughout the Downtown plan area that are intended to raise overall development capacity and thereby also provide sufficient economic benefit to promote redevelopment of the Plan area (See Attachment #1 Precise Plan p. 99 Figure 5-4). Allowable building heights are reduced at some locations from the current General Plan, which sets a generic maximum height of 50 feet over the entire Downtown. In the Precise Plan lower maximum heights of 28 feet or 40 feet are established at the interface between new and existing land uses that would be most sensitive to an adjacent, higher-density development. These lower height limits are located on portions of Blocks H, I and J and along the outside edges of most blocks.

However, the height limit is increased on every block to some degree, with maximum heights of 59 to 98 feet allowed at various locations. The Precise Plan anticipates the ability for further increases in height with the provision of a community benefit, but the terms that would allow this have not been City of Santa Clara Page 11 of 15 Printed on 10/23/2023 powered by Legistar™
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included at this time. While the maximum heights have been reduced at some locations, the new maximums would still allow a significant intensification over existing land uses, much of which are one-story, and are intended to provide sufficient intensification to support economic feasibility while meeting the need to minimize impacts on adjacent, primarily single-family residential development.

As discussed elsewhere, developers may also take advantage of State legislation which grants increased densities when the project meets affordability criteria. On the whole, the proposed maximum heights implement a careful balance of community interests in maintaining land use compatibility while also providing a land use framework conducive to new development activity.

Community Benefits Program
At the onset of the community planning process, the community wanted to include in the Precise Plan a Community Benefit Program. The DCTF discussed this concept and different methodologies for its implementation, but concluded that additional work was necessary before it could be incorporated into the Precise Plan. Specifically, the DCTF preferred a fee-based program that would require preparation of a supporting nexus study. Accordingly, the draft Precise Plan under consideration does not include a community benefits program and the DCTF has stated a desire to continue working on this topic after adoption of the Precise Plan and Form-based Code so that development might proceed according to the base densities allowed within those documents while the community develops a specific system for granting increased heights and densities. Further work by the DCTF and preparation of a nexus study would both require additional appropriation and direction by the City Council.

Based on community and DCTF discussion to this point, the community benefits program is envisioned to allow additional development rights through increased allowances for building height in exchange for the provision by the developer of a defined community benefit. The preliminary list of community benefits that could qualify a developer for such a height increase includes provision within the project of one or more of the following desired community amenities: movie theater, cultural arts center, market (food) hall, public parking garage, and visual and performing art venues. The DCTF also discussed community benefit being established through conservation of historic resources or contributing buildings to historic districts, land dedication for public realm that exceeds standard requirements, and enhanced public realm or transit infrastructure contributions beyond those otherwise required. To procedurally achieve the Community Benefit and resulting height increase, a developer would need to apply for, and execute with the City Council, a Development Agreement that would set the terms of delivering the benefit. It was intended that the building height increase granted would be commensurate with the level of community benefit contribution as determined at the City’s discretion.

With the review of the draft Precise Plan, the community voiced concern over the approval of a Community Benefit Program that would be subject to City discretion to implement as it would not be adequately predictable or knowable to the community or the developer. The City’s consultant provided alternative ideas and examples for achieving community benefits, and the DCTF agreed on an alternative direction with a more quantified structure, including the potential establishment of a community benefit fee. However, this alternative would require preparation of a nexus study, which is not part of the current project scope. Therefore, the DCTF voted unanimously to remove the community benefits program from the current version of the otherwise completed Precise Plan and Form Based Code draft documents.

Conclusion
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The Downtown Precise Plan, accompanying Form Based Zoning Code, and project EIR have been prepared through an extensive community-based planning process, which has provided a significant amount of time for discussion of the various components of the project. The Precise Plan attempts to provide a development framework to support the implementation of a grid street system, connected public spaces, and essential land uses that implement a sensitively and specifically designed urban form consistent with the Community’s vision and the goals and policies set forth in the General Plan.

ENVIRONMENTAL REVIEW
The action being considered takes into account the potential environmental impacts of the project through the preparation of an Environmental Impact Report (EIR) for the project. The EIR was prepared in accordance with the California Environmental Quality Act (CEQA) and circulated for a 45- day public review between May 31, 2023 and July 17, 2023. A total of three comments were received during the comment period. Two were from a local/regional agency, Valley Water and Santa Clara Valley Transportation Authority. The third letter received was from an organization, the Judicial Council of California. None of the comment letters identified a new significant impact or have provided substantial evidence that the CEQA analysis is otherwise inadequate. Recirculation of the EIR is therefore not required. Responses to the Draft EIR comments, as well as minor text changes and clarifications, in the form of a Final EIR, were made available to the public through the City’s website on October 11, 2023, and have been forwarded on to any commenters on the Draft EIR. A website link to the Final EIR, MMRP, CEQA Findings, and Response to Comments is provided in Attachment 1 to this report.

The EIR identified potential environmental impacts associated with project and identified air quality, biological, cultural resources, geology and soils, hazards and hazardous materials, noise, and tribal cultural resources as having impacts that with the incorporation of mitigation measures would be reduced to less than significant. The EIR also identified Greenhouse Gas Emissions as having a significant unavoidable impact with mitigation incorporated and Land Use and Planning as having a significant unavoidable impact.

For Greenhouse Gas Emissions, the EIR identifies that the Precise Plan is not fully consistent with the development assumptions of the 2022 Climate Action Plan (CAP), in that only a portion of the Plan’s development capacity was accounted for in the 2022 CAP assumptions. As such, projects approved prior to January 1, 2031 would be required to demonstrate conformance with the 2022 CAP measures and projects approved after December 31, 2030 would not be covered by the 2022 CAP and will be required to implement Mitigation Measures GHG-1.1 and GHG-1.2 as outlined in the EIR.

For Land Use and Planning, the EIR identifies that even with implementation of the Greenhouse Gas Emissions Mitigation Measures GHG1.1 and GHG-1.2, projects initiated after 2030 could conflict or otherwise interfere with the statewide GHG reduction measures set forth by SB 375. As a result, implementation of the Precise Plan would result in a significant unavoidable land use impact.

A detailed discussion of the potential impacts and mitigation measures to be applied are specified in the EIR and would be implemented through project conditions of approval and the Mitigation Monitoring and Reporting Program (MMRP) for the proposed project.

FISCAL IMPACT
There is no fiscal impact to the City other than administrative staff time and expense to prepare this report.

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COORDINATION
This report has been coordinated with the City Attorney’s Office.

PUBLIC CONTACT
Public contact was made by posting the Council agenda on the City’s official-notice bulletin board outside City Hall Council Chambers. A complete agenda packet is available on the City’s website and in the City Clerk’s Office at least 72 hours prior to a Regular Meeting and 24 hours prior to a Special Meeting. A hard copy of any agenda report may be requested by contacting the City Clerk’s Office at (408) 615-2220, email [email protected] <mailto:[email protected]> or at the public information desk at any City of Santa Clara public library. Furthermore, public outreach for the project is consistent with City Council Resolution No. 17-8456, regarding public outreach policy.

On October 11, 2023, a notice of public hearing of this item was posted in three conspicuous locations within 1,000 feet of the project site. A notice of public hearing was also published in the Weekly, a newspaper of general circulation in the City, on October 11, 2023. As of the time of this report, the Community Development Department has not received any comments on the project.

However, public input has been received and considered throughout the planning process as described in more detail below.

Community Outreach
Over the course of the Downtown Precise Plan planning process, the planning team has received feedback from community members and stakeholders in the following ways:
§ 42 Downtown Community Task Force (DCTF) meetings. Details of each meeting, including meeting materials and videos recordings can be found under the Task Force page of the Downtown Precise Plan website.
§ Community Open House on November 19, 2022.
§ Placemaking Community Workshop on October 12, 2021.
§ Two online surveys on the topics of Land Use Concepts during May 2020 and Placemaking during October 2021.
§ Two “Meeting in a Box” activities distributed to the community in January/February 2020 and June 2020.
§ A lunchtime student engagement workshop at Santa Clara University on January 29, 2020. § Downtown Retail 101 Community Workshop on January 16, 2020. § Meetings with stakeholders and technical advisors from January through March 2020.

Summaries and meeting materials for all the community engagement activities can be found on the Downtown Precise Plan website at: www.santaclaraca.gov/downtown.

ALTERNATIVES

1. Provide alternate direction regarding the adoption of a resolution approving and certifying the Final EIR prepared for the Santa Clara Downtown Precise Plan (SCH # 2022010282), including CEQA Findings and a Statement of Overriding Considerations.

2. Provide alternate direction regarding the adoption of a resolution approving the Downtown Precise Plan.

3. Provide alternate direction regarding the adoption of a resolution approving a General Plan text amendment to modify the Downtown Core land use designation, and amending the City of Santa Clara Page 14 of 15 Printed on 10/23/2023 powered by Legistar™
23-1115 Agenda Date: 10/25/2023
General Plan Land Use diagrams for Phases II and III to reflect the Downtown Precise Plan.

4. Provide alternate direction regarding the adoption of an ordinance amending the zoning code to create the Downtown Zoning district.

RECOMMENDATION
That the Planning Commission adopt Resolutions recommending that the City Council:

1. Adopt a resolution approving and certifying the Final EIR prepared for the Santa Clara Downtown Precise Plan (SCH # 2022010282), including CEQA Findings and a Statement of Overriding Considerations.

2. Adopt a resolution approving the Downtown Precise Plan.

3. Adopt a resolution approving a General Plan text amendment to modify the Downtown Core land use designation, and amending the General Plan Land Use diagrams for Phases II and III to reflect the Downtown Precise Plan.

4. Adopt an ordinance amending the zoning code to create the Downtown Zoning district.

Reviewed by: Andrew Crabtree, Director of Community Development Approved by: Jōvan D. Grogan, City Manager

ATTACHMENTS

1. Web Links to the Precise Plan, Form Base Zoning Code, Environmental Impact Report, CEQA Findings, Statement of Overriding Considerations, Downtown website

2. Final EIR Resolution

3. Downtown Precise Plan Resolution

4. General Plan Amendment Resolution

5. Form Based Zoning Code Resolution
City of Santa Clara Page 15 of 15 Printed on 10/23/2023 powered by Legistar™
Draft Downtown Precise Plan, Form Based Code, EIR - Web links Downtown Website:

The Following is a link to the Downtown website where you will find you can find all of the background information for the planning process including community outreach summaries and the Precise Plan and the Form Based Zoning Code documents for your review. https://www.santaclaraca.gov/our-city/departments-a-f/community-development/planningdivision/specific-plans/downtown-precise-plan Downtown Precise Plan (direct link):
https://www.santaclaraca.gov/home/showpublisheddocument/82509 Form Based Zoning Code (direct link):
https://www.santaclaraca.gov/home/showpublisheddocument/82495 Environmental Impact Report (EIR), MMRP, CEQA Findings, Response to Comments:
https://www.santaclaraca.gov/Home/Components/BusinessDirectory/BusinessDirectory/437/36 49?selcat=257&npage=2
All of these documents are on file and available for viewing in Community Development Department, Planning Division.

Resolution/Downtown Precise Plan WSA Page 1 of 2
Rev: 7/27/2023
RESOLUTION NO. _____

A RESOLUTION OF THE CITY OF SANTA CLARA, CALIFORNIA

APPROVING A WATER SUPPLY ASSESSMENT FOR THE

DOWNTOWN PRECISE PLAN
WHEREAS, the City of Santa Clara (“City”) approved and adopted the 2020 Urban Water Management Plan in 2021;
WHEREAS, California Water Code Section 10910 and Section 15155(b) of the Guidelines to the California Environmental Quality Act ("CEQA") require a water utility to prepare a Water Supply Assessment for development applications for "water-demand projects”; WHEREAS, the City is a public water supplier within the City limits and the City Council of the City of Santa Clara is the governing body of the City's public water system; WHEREAS, the City of Santa Clara requires that landscaping for projects be drought tolerant and recycled water be used for irrigation, cooling towers and other permitted uses when properties are proximate to recycled water resources to reduce the cumulative use of potable water; and WHEREAS, City Staff prepared a Water Supply Assessment for the Downtown Precise Plan ("WSA").

NOW THEREFORE, BE IT RESOLVED BY THE CITY OF SANTA CLARA AS FOLLOWS:

1. That the Water Supply Assessment for the proposed the Downtown Precise Plan is attached to the RTC for the Council meeting of December 5, 2023.

2. Approval of WSA. The Council has reviewed the WSA at a regular public meeting conducted on December 5, 2023. Based upon the data and conclusions set forth therein, and the evidence and testimony presented at the public meeting, the Council hereby finds that there is adequate water to supply the Downtown Precise Plan without creating a negative impact on the groundwater basin and that the City has an adequate supply to provide water for the Downtown Precise Plan during single or multiple dry years for at least a 20-year projection, and, the council hereby approves the WSA.

Resolution/Downtown Precise Plan WSA Page 2 of 2
Rev: 7/27/2023

3. Direction to Staff. Staff is hereby directed to include the WSA, the 2020 City of Santa Clara Urban Water Management Plan, and any other applicable Urban Water Management Plan related documents in the appendix of the Environmental Impact Report for the Downtown Precise Plan.

4. Effective date. This resolution shall become effective immediately.

I HEREBY CERTIFY THE FOREGOING TO BE A TRUE COPY OF A RESOLUTION PASSED AND

ADOPTED BY THE CITY OF SANTA CLARA, CALIFORNIA, AT A REGULAR MEETING THEREOF HELD ON THE 5TH DAY OF DECEMBER, 2023, BY THE FOLLOWING VOTE:

AYES: COUNCILORS:

NOES: COUNCILORS:

ABSENT: COUNCILORS:

ABSTAINED: COUNCILORS:

ATTEST: ______________________________

NORA PIMENTEL, MMC

ASSISTANT CITY CLERK

CITY OF SANTA CLARA
Attachments incorporated by reference: None
S:\Attorney\RESOLUTIONS\Form Resolution-City.doc
Resolution/Downtown Precise Plan EIR Page 1 of 6
Rev: 7/27/2023
RESOLUTION NO. _____

A RESOLUTION OF THE CITY OF SANTA CLARA, CALIFORNIA

APPROVAL AND CERTIFICATION OF A FINAL ENVIRONMENTAL

IMPACT REPORT, FOR THE ADOPTION OF CEQA FINDINGS

AND A STATEMENT OF OVERRIDING CONSIDERATIONS WITH

RESPECT THERETO, AND ADOPTION OF A MITIGATION

MONITORING AND REPORTING PROGRAM FOR THE

DOWNTOWN PRECISE PLAN AND FORM BASED ZONING CODE
SCH No.: 2022010282
Santa Clara Downtown Precise Plan Environmental Impact Report WHEREAS, the City intends to adopt the Downtown Precise Plan and Form Based Zoning Code, a Plan and Zoning District for a revitalized Downtown with a reconnected street grid, new public spaces and up to 1,071 residential units, 531,720 square feet of office space, and 197,900 square feet of commercials uses, located on approximately 25 acres bounded by Benton Street, Lafayette Street, Homestead Road, and Madison Street, which is currently developed with a mix of residential, office, and retail uses in buildings ranging from one to seven stories; and; WHEREAS, a Precise Plan provides detailed guidance through goals, policies, and implementation measures with more detail than the General Plan;
WHEREAS, a Form Based Zoning Code provides development standards that implement the direction of the Precise Plan;
WHEREAS, the proposed Downtown Precise Plan is consistent with the Goals and Policies of the Future Focus Areas section in the General Plan;
WHEREAS, as a part of implementing the Precise Plan, the City is contemplating the adoption of a General Plan Amendment (“GPA”) to amend the General Plan land use diagram by changing the existing land use designations of the Project Site from Downtown Core, Community Mixed Use, and Medium Density Residential to a new designation, Downtown, that allows for a mix of residential, commercial, office, and civic uses with site specific building heights ranging from two to seven stories;
WHEREAS, the City is contemplating the amendment of SCCC Title 18, the Zoning Code, to Resolution/Downtown Precise Plan EIR Page 2 of 6
Rev: 7/27/2023
replace the CD - Downtown Commercial zoning district with a Downtown zoning district and associated Form-Based Zoning Code that implements and is consistent with the proposed Precise Plan, and to apply this zoning district across the entire Project Site; WHEREAS, the Project approvals will include this Resolution; the CEQA Resolution; the General Plan Amendment Resolution; the Precise Plan Resolution; and the Ordinance for the Zoning Code Text Amendment and Rezoning Ordinance (collectively, the “Approvals”); WHEREAS, on January 19, 2022 the City of Santa Clara (“City”) distributed a Notice of Preparation of a Draft Environmental Impact Report (“DEIR”) for the Downtown Precise Plan that included a total of approximately 1,317,600 square feet of housing (up to 1,326 residential units); 669,500 square feet of office/hotel; 197,900 square feet of retail/retail ready/and entertainment; and 44,300 square feet of public space and on January 19, 2022 posted the Notice at the Santa Clara County Clerk’s office, soliciting guidance on the scope and content of the environmental information to be included in the DEIR; WHEREAS, the DEIR was prepared in accordance with CEQA and the City circulated copies of the DEIR and Notice of Availability to the public agencies which have jurisdiction by law with respect to the Project, as well as to other interested persons, organizations and agencies, and the City sought the comments of such persons, organizations and agencies on May 31, 2023 for a 45-day review period, ending on July 17, 2023 (“Comment Period”);
WHEREAS, the City prepared written responses to the comments received during the Comment Period and included those responses in a Final Environmental Impact Report (“FEIR”). The FEIR consists of a list of agencies and organizations to whom the DEIR was sent, a list of the comment letters received on the DEIR, revisions to the text of the DEIR, responses to comments received on the DEIR, and copies of comment letters. The FEIR was circulated for a 10-day review period beginning on October 11, 2023;
WHEREAS, the DEIR and FEIR constitute the EIR for the Project; WHEREAS, the EIR identified certain significant and potentially significant adverse effects on the Resolution/Downtown Precise Plan EIR Page 3 of 6
Rev: 7/27/2023
environment that would be caused by the Project as proposed; WHEREAS, the EIR outlined various mitigation measures that would substantially lessen or avoid the Project’s significant effects on the environment, as well as alternatives to the Project as proposed that would provide some environmental advantages; WHEREAS, the City is required, pursuant to the California Environmental Quality Act (“CEQA”) (Public Resources Code § 21000 et seq.), to adopt all feasible mitigation measures or feasible project alternatives that can substantially lessen or avoid any significant environmental effects of the Project;
WHEREAS, the EIR analyzed a No Project alternative for the Precise Plan area, that contemplates the existing conditions remaining substantially the same, and a Reduced Density alternative; WHEREAS, Public Resources Code § 21081, subdivision (a) requires a lead agency, before approving a project for which an EIR has been prepared and certified, to adopt findings specifying whether mitigation measures and, in some instances, alternatives discussed in the EIR, have been adopted or rejected as infeasible;
WHEREAS, the “CEQA Findings” attached to this Resolution is a set of Findings of Fact and a Statement of Overriding Considerations prepared in order to satisfy the requirements of Public Resources Code § 21081, subdivision (a);
WHEREAS, the City Council has determined that none of the alternatives addressed in the EIR, would be both feasible and environmentally superior to the Project as proposed. The No Project alternative and the Reduced Density alternative would not sufficiently satisfy the Project Objectives.

The details supporting these determinations are set forth in the CEQA Findings; WHEREAS, in taking this course, the City Council has acted consistent with the CEQA mandate to look to project mitigations and/or alternatives as a means of substantially lessening or avoiding the environmental effects of projects as proposed;
WHEREAS, many of the significant and potentially significant environmental effects associated with the Project can either be substantially lessened or avoided through the inclusion of mitigation Resolution/Downtown Precise Plan EIR Page 4 of 6
Rev: 7/27/2023
measures proposed in the EIR;
WHEREAS, the City Council, in reviewing the Project, intends to adopt all mitigation measures set forth in the EIR;
WHEREAS, Section 15025(c) of the CEQA Guidelines provides that whenever an advisory body such as a Planning Commission is required to make a recommendation on a project to the decisionmaking body, the advisory body must also review and consider the EIR; WHEREAS, on October 25, 2023, the Planning Commission reviewed and considered the EIR at a duly noticed public meeting, at the conclusion of which, the Commission voted to recommend that the Council approve and certify the EIR;
WHEREAS, notice of the December 5, 2023 public hearing on the proposed project was published in the Santa Clara Weekly, a newspaper of general circulation for the City, on October 11, 2023; WHEREAS, notices of the December 5, 2023 public hearing on the proposed project were mailed to all property owners within 1,000 feet of the Project Site, according to the most recent assessor’s roll, on October 11, 2023; and,
WHEREAS, the City Council reviewed the EIR and Mitigation Monitoring and Reporting Program, attached as the “MMRP”, as well as a set of CEQA Findings and, in accordance with the requirements of CEQA, along with the City Staff report pertaining to the EIR for the Project (SCH # 2022010282), and all evidence received at a duly noticed public hearing on December 5, 2023. All of these documents and evidence are incorporated herein by reference into this Resolution.

NOW THEREFORE, BE IT RESOLVED BY THE CITY OF SANTA CLARA AS FOLLOWS:

1. That the City Council hereby finds that the above Recitals are true and correct and by this reference makes them a part hereof.

2. That the City Council hereby finds that the EIR has been completed in compliance with CEQA.

3. That the City Council hereby finds the EIR has been presented to the City Council, which reviewed and considered the information and analysis contained therein.

Resolution/Downtown Precise Plan EIR Page 5 of 6
Rev: 7/27/2023

4. That the City Council hereby finds, pursuant to Public Resources Code Section 21081 and California Code of Regulations, Title 14, Section 15091, that many of the proposed mitigation measures described in the EIR are feasible, and therefore will become binding upon the City and affected landowners and their assigns or successors in interest as conditions of approval when the Project is approved.

5. That the City Council hereby finds that none of the Project Alternatives set forth in the EIR can feasibly substantially lessen or avoid those significant adverse environmental effects not otherwise lessened or avoided by the adoption of all feasible mitigation measures.

6. That, in order to comply with Public Resources Code Section 21081.6, the City Council adopts the Mitigation Monitoring and Reporting Program as set forth in the attached “MMRP”. The MMRP is designed to ensure that, during project implementation, the City, affected landowners, their assigns and successors in interest and any other responsible parties comply with the feasible mitigation measures identified. The MMRP identifies, for each mitigation measure, the action to be taken and the party responsible for implementation.

7. That the City Council hereby finds that the EIR set forth program and cumulative environmental impacts that are significant and unavoidable that cannot be mitigated or avoided through the adoption of feasible mitigation measures or feasible alternatives. As to these impacts, the City Council finds that there exist certain overriding economic, social and other considerations for approving the Project that justify the occurrence of those impacts, as detailed in the “CEQA Findings” exhibit attached hereto.

8. Based on the findings set forth in this Resolution, the evidence in the City Staff Report, and the attached CEQA Findings, the City Council approves and certifies the EIR, adopts the CEQA findings concerning mitigation measures, adopts the MMRP, makes findings concerning alternatives and makes findings that there exist certain overriding economic, social and other considerations for approving the Project that justify the occurrence of those associated impacts and adopts the CEQA Findings and Statement of Overriding Considerations, all in accordance with CEQA for the Project.

Resolution/Downtown Precise Plan EIR Page 6 of 6
Rev: 7/27/2023

9. Pursuant to Section 15091(e) of the CEQA Guidelines, the City Council hereby designates the Director of Community Development as the Custodian of Records for the Project, and the Planning Division at City Hall, 1500 Warburton Avenue, Santa Clara, California, is the location of the documents and other material that constitute the record of proceedings upon which this decision is based.

10. Effective date. This resolution shall become effective immediately.

I HEREBY CERTIFY THE FOREGOING TO BE A TRUE COPY OF A RESOLUTION PASSED

AND ADOPTED BY THE CITY OF SANTA CLARA, CALIFORNIA, AT A REGULAR MEETING THEREOF HELD ON THE 5
TH DAY OF DECEMBER, 2023, BY THE FOLLOWING VOTE:

AYES: COUNCILORS:

NOES: COUNCILORS:

ABSENT: COUNCILORS:

ABSTAINED: COUNCILORS:

ATTEST: ______________________________

NORA PIMENTEL, MMC

ASSISTANT CITY CLERK

CITY OF SANTA CLARA
Attachments incorporated by reference:

1. MMRP

2. CEQA Findings
S:\Attorney\RESOLUTIONS\Form Resolution-City.doc
Resolution/Downtown Precise Plan Page 1 of 4
Rev: 7/27/2023
RESOLUTION NO. _____

A RESOLUTION OF THE CITY OF SANTA CLARA, CALIFORNIA

APPROVING THE DOWNTOWN PRECISE PLAN
WHEREAS, the City of Santa Clara (the “City”) is contemplating the adoption of the Downtown Precise Plan (the “Project”), a plan to implement the community’s vision and objectives for a vibrant, pedestrian-oriented destination Downtown with a reestablished street grid; WHEREAS, the Downtown Precise Plan is a long-range planning document that provides detailed guidance for future land uses, urban design elements, and right-of-way design concepts; WHEREAS, the Precise Plan represents the implementation of the General Plan’s goals and policies for the Downtown Focus Area;
WHEREAS, the Precise Plan is located on approximately 25 acres of land located in Santa Clara’s historic Downtown bounded by Benton Street to the north, Lafayette Street to the east, Homestead Road to the south, and Madison Street to the west that are currently developed with commercial, office, and residential uses;
WHEREAS, the development capacity of the Project is up to 1,071 residential units, 531,720 square feet of office space, 197,900 square feet of commercial/retail space, and 44,300 square feet of public space;
WHEREAS, the framework for the Plan was developed with a focus on building form and height; WHEREAS, new development within the Plan area may be used for housing, offices, hotels, retail, civic or cultural uses, or a mix of these uses;
WHEREAS, the allowable building heights, massing, and placement determine the ultimate development capacity for the Project;
WHEREAS, as a part of implementation the Precise Plan, the City is also proposing to amend Title 18 (“Zoning”), of the City Code to create a new Downtown zoning district that implements the proposed Precise Plan, and to apply that zoning designation across the Project Site; WHEREAS, Santa Clara City Charter Section 1007 and Government Code sections 65353 and Resolution/Downtown Precise Plan Page 2 of 4
Rev: 7/27/2023
65453 require that the Planning Commission provide input to the City Council on proposed longrange plans; and, WHEREAS, on October 25, 2023, the Planning Commission conducted a duly noticed public hearing to consider the Project, at the conclusion of which the Commission recommended that the City Council approve the proposed Precise Plan; and WHEREAS, notice of the public hearing on the proposed Precise Plan was published in the Santa Clara Weekly, a newspaper of general circulation for the City, on October 11, 2023; WHEREAS, notices of the public hearing on the proposed Precise Plan were mailed to all property owners within 1,000 feet of the Project Site, according to the most recent assessor’s roll, and to all local agencies expected to provide essential facilities or services to the project, on October 11, 2023;
WHEREAS, before considering adoption of the Precise Plan, the City Council reviewed and considered the potential environmental impacts of the Project, including the implementing General Plan Amendment, Zoning Code Amendment, and identified mitigation measures, and adopted and certified the Environmental Impact Report (“EIR”) for the Project (SCH #2022010282), as well as a set of CEQA Findings and a Statement of Overriding Considerations, in accordance with the requirements of CEQA; and
WHEREAS, on December 5, 2023, the City Council reviewed the Precise Plan and conducted a public hearing, at which time all interested persons were given an opportunity to give testimony and provide evidence in support of and in opposition to the proposed Precise Plan.

NOW THEREFORE, BE IT RESOLVED BY THE CITY OF SANTA CLARA AS FOLLOWS:

1. That the City Council hereby finds that the above Recitals are true and correct and by this reference makes them a part hereof.

2. Precise Plan Findings. That the City Council finds and determines that the Precise Plan is in the interest of the public good for the following reasons:

A. The proposed Precise Plan is deemed to be in the public interest, in that:

Resolution/Downtown Precise Plan Page 3 of 4
Rev: 7/27/2023
The Precise Plan is located in an urbanized area served by existing municipal services and implements smart growth principles by redeveloping underutilized properties with higher intensity residential, commercial, or office uses, or a mix of those uses, that will contribute to the City both socially and economically.

B. The proposed Precise Plan is consistent and compatible with the General Plan and any implementation programs that may be affected, in that:

The Precise Plan furthers and is consistent with the goals, policies and major strategies of the General Plan that enhance the City’s quality of life, preserve and cultivate neighborhoods, promote sustainability, enhance City identity, support General Plan Focus Areas and community vitality, maintain the City’s fiscal health and quality of services, and maximize health and safety benefits with the modification of an existing new land use designation that allows for the development of a high-density mixed-use transit-oriented environment.

C. The proposed Precise Plan has been processed in accordance with the applicable provisions of the California Government Code and the California Environmental Quality Act (CEQA), in that:

A Draft Environmental Impact Report (“DEIR”) was prepared in accordance with CEQA and the City circulated copies of the DEIR and Notice of Availability to the public agencies which have jurisdiction by law with respect to the Project, as well as to other interested persons, organizations and agencies, and the City sought the comments of such persons, organizations and agencies. The City prepared and circulated written responses to the comments received during the Comment Period and included those responses in a Final Environmental Impact Report (“FEIR”), in accordance with CEQA.

D. The potential impacts of the proposed amendment have been assessed and have been determined not to be detrimental to the public health, safety, or welfare, in that:

A Mitigation Monitoring and Reporting Program (MMRP) has been prepared for implementation with development under the Precise Plan in order to reduce potentially significant Resolution/Downtown Precise Plan Page 4 of 4
Rev: 7/27/2023
impacts identified in the DEIR and FEIR, that combined constitute the EIR for the Project, to less than significant and a set of CEQA Findings and a Statement of Overriding Considerations for the significant unavoidable impacts that cannot be mitigated to less than significant has been prepared in accordance with CEQA; and the City Council adopted all of these documents.

3. That based on the findings set forth in this Resolution, the Approvals, and the evidence in the City Staff Report and such other evidence as received at the public hearing on this matter, the City Council hereby adopts the Precise Plan.

4. Effective date. This resolution shall become effective immediately.

I HEREBY CERTIFY THE FOREGOING TO BE A TRUE COPY OF A RESOLUTION PASSED

AND ADOPTED BY THE CITY OF SANTA CLARA, CALIFORNIA, AT A REGULAR MEETING THEREOF HELD ON THE 5
TH DAY OF DECEMBER, 2023, BY THE FOLLOWING VOTE:

AYES: COUNCILORS:

NOES: COUNCILORS:

ABSENT: COUNCILORS:

ABSTAINED: COUNCILORS:

ATTEST: ______________________________

NORA PIMENTEL, MMC

ASSISTANT CITY CLERK

CITY OF SANTA CLARA
Attachments incorporated by reference: None
S:\Attorney\RESOLUTIONS\Form Resolution-City.doc
Resolution/Downtown Precise Plan General Plan Amendment Page 1 of 4 Rev: 7/27/2023
RESOLUTION NO. _____

A RESOLUTION OF THE CITY OF SANTA CLARA, CALIFORNIA

TO APPROVE A GENERAL PLAN AMENDMENT TO AMEND THE

MAP AND TEXT OF THE GENERAL PLAN TO MODIFY THE

DOWNTOWN CORE LAND USE DESIGNATION
WHEREAS, on October 17, 2019, the City contracted with the planning consulting firm WRT to develop a Precise Plan for a 10-block area of the Downtown Focus Area as designated in the 2010- 2035 General Plan;
WHEREAS, the General Plan has a Downtown Core land use designation that is applied to seven acres of the Downtown Focus area, and as such a modification to the General Plan map and the General Plan text is required to allow for the designation to be applied to property within the boundary of the Precise Plan;
WHEREAS, the text amendment modifies the “Downtown Core” land use designation to rename it as “Downtown” and apply only to a 10-block area of the Downtown Focus Area; WHEREAS, Santa Clara City Charter Section 1007 and Government Code Section 65353 require that the Planning Commission provide input to the City Council on any proposed General Plan Amendment;
WHEREAS, on October 25, 2023 the Planning Commission conducted a duly noticed public hearing and recommended that the Council approve the proposed General Plan Amendment; WHEREAS, Government Code Section 65355 requires the City Council to hold a public hearing prior to adopting an amendment of the General Plan;
WHEREAS, notice of the public hearing on the proposed General Plan Amendment was published in the Santa Clara Weekly, a newspaper of general circulation for the City, on October 11, 2023; WHEREAS, before considering the subject General Plan Text Amendment, the City Council reviewed and considered the associated Environmental Impact Report for the Santa Clara Downtown Precise Plan;
WHEREAS, the City Council has reviewed the General Plan Text Amendment; and Resolution/Downtown Precise Plan General Plan Amendment Page 2 of 4 Rev: 7/27/2023
WHEREAS, on December 5, 2023, the City Council conducted a duly noticed public hearing to consider the General Plan Amendment, at which time all interested persons were given an opportunity to give testimony and provide evidence in support of and in opposition to the proposed General Plan Amendment.

NOW THEREFORE, BE IT RESOLVED BY THE CITY OF SANTA CLARA AS FOLLOWS:

1. That the City Council hereby finds that the above Recitals are true and correct and by this reference makes them a part hereof.

2. General Plan Amendment Findings. That the City Council finds and determines that the General Plan Amendment is in the interest of the public good for the following reasons:

A. The proposed General Plan Amendment is deemed to be in the public interest, in that:

The proposed General Plan Amendment will align the proposed Precise Plan with the General Plan land use designation and map.

B. The proposed General Plan Amendment is consistent and compatible with the rest of the General Plan and any implementation programs that may be affected, in that:

The Project furthers and is consistent with the goals, policies and major strategies of the General Plan that enhance the City’s quality of life, promote sustainability, enhance City identity, support Focus Areas and community vitality, maintain the City’s fiscal health and quality of services, by allowing for an increase in density for a mix of residential, office, retail and civic office uses within 10 blocks of the Downtown Focus Area.

C. The proposed General Plan Amendment has been processed in accordance with the applicable provisions of the California Government Code and the California Environmental Quality Act (CEQA), in that:

An Environmental Impact Report (“EIR”) was prepared in accordance with CEQA. The City Council has read and considered the EIR.

D. The potential impacts of the proposed General Plan Amendment have been Resolution/Downtown Precise Plan General Plan Amendment Page 3 of 4 Rev: 7/27/2023
assessed and have been determined not to be detrimental to the public health, safety, or welfare, in that:

A Mitigation Monitoring and Reporting Program (MMRP) has been prepared for implementation with Project development to reduce potentially significant impacts identified in the EIR to less than significant and a set of CEQA Findings and a Statement of Overriding Considerations have been prepared for the significant unavoidable impacts that cannot be mitigated to less than significant; and the City Council adopted these documents.

3. That the City Council hereby amends the General Plan by revising Section 5.2.2 Land Use Classifications and Diagram, Downtown land use designation of the General Plan with the following text:
“Downtown Core. This classification is exclusively for land so designated within the Downtown Precise Plan boundary that is bounded by Benton Street, Lafayette Street, Homestead Road, and Madison Street Focus Area. It covers the eight blocks of the University Redevelopment Project Area, approximately seven 25-acres, planned for high density residential, office, civic, cultural, hotel, and retail uses that will draw local and regional patrons and increase pedestrian activity in the City’s center. The Precise Plan provides goals, policies and implementation measures that governs development Development under this classification will result in approximately 400 residential units and 130,000 square feet of non‐residential development, excluding any space devoted to civic or public uses, as illustrated on Figure 5.4‐3.”

4. That pursuant to Government Code § 65356, the City Council hereby amends the General Plan by changing the General Plan Land Use Designation for the Project Site by modifying Figures modifying Figures 5.2-2 and 5.2-3 of the General Plan to the Downtown land use designation.

5. That based on the findings set forth in this Resolution, the EIR Resolution and the evidence in the City Staff Report and such other evidence as received at the public hearing on this matter, the City Council hereby approves the General Plan Amendment.

Resolution/Downtown Precise Plan General Plan Amendment Page 4 of 4 Rev: 7/27/2023

6. Effective date. This resolution shall become effective immediately.

I HEREBY CERTIFY THE FOREGOING TO BE A TRUE COPY OF A RESOLUTION PASSED

AND ADOPTED BY THE CITY OF SANTA CLARA, CALIFORNIA, AT A REGULAR MEETING THEREOF HELD ON THE 5
TH DAY OF DECEMBER, 2023, BY THE FOLLOWING VOTE:

AYES: COUNCILORS:

NOES: COUNCILORS:

ABSENT: COUNCILORS:

ABSTAINED: COUNCILORS:

ATTEST: ______________________________

NORA PIMENTEL, MMC

ASSISTANT CITY CLERK

CITY OF SANTA CLARA
Attachments incorporated by reference: None
S:\Attorney\RESOLUTIONS\Form Resolution-City.doc
Ordinance/Downtown Form-Based Zoning District Page 1 of 4 Rev: 09/2019
ORDINANCE NO. _____

AN ORDINANCE OF THE CITY OF SANTA CLARA,
CALIFORNIA, AMENDING TITLE 18 OF “THE CODE OF
THE CITY OF SANTA CLARA, CALIFORNIA” TO ADD A
NEW CHAPTER 18.11, REGULATIONS FOR THE

DOWNTOWN FORM-BASED ZONING DISTRICT
WHEREAS, the City of Santa Clara (the “City”) is contemplating the adoption of the Downtown Precise Plan (the “Project”), a plan to implement the community’s vision and objectives for a vibrant, pedestrian-oriented destination Downtown with a reestablished street grid with up to 1,071 residential units, 531,720 square feet of office space, 197,900 square feet of commercial/retail space, and 44,300 square feet of public space, located on approximately 25 acres of land located in the historic Downtown bounded by Benton Street to the north, Lafayette Street to the east, Homestead Road to the south, and Madison Street to the west;
WHEREAS, the Project site is located within the Downtown Focus Area of the General Plan;
WHEREAS, the General Plan contemplates that Focus Areas represent locations with opportunities for more intense development with limited impact on existing neighborhoods; WHEREAS, the Precise Plan represents the implementation of the General Plan’s goals and policies for the Downtown Focus Area;
WHEREAS, as a part of implementation of the Precise Plan, the City intends to adopt a General Plan Amendment (“GPA”) to amend the General Plan land use diagram by changing the existing land use designation of the Project Site from High Density Residential, Community Mixed Use, and Downtown Core to Downtown; WHEREAS, the Downtown Precise Plan is currently zoned CD - Downtown Commercial, Ordinance/Downtown Form-Based Zoning District Page 2 of 4 Rev: 09/2019
OG - General Office, CC - Community Commercial, R1-6L – Single Family, B – Public, Quasi-Public Park or Recreation, and PD Planned Development; WHEREAS, the Santa Clara City Code (“SCCC”) currently does not include the required zoning district to implement the General Plan designation proposed in the Downtown Precise Plan area;
WHEREAS, in order to effectuate the Project at the higher-intensity form of development provided in the Precise Plan, it therefore is necessary to (a) create a new zoning district that implements the Precise Plan in the project area, and (b) rezone the Downtown Precise Plan area using the Downtown Form Based zoning designation; and WHEREAS, the HT – Historic Combining zoning district is an overly district intended to preserve historic landmarks and is applied to one property in the Plan area with APN 269- 20-095 (906 Monroe Street), and the proposed rezoning will not remove the overlay, but change the underlying combining district;
WHEREAS, SCCC Section 18.112.040 provides for the review and recommendation by the Planning Commission of all proposed zoning amendments before any action is taken by the City Council;
WHEREAS, on October 25, 2023 the Planning Commission conducted a duly noticed public hearing and recommended that the Council approve the proposed Downtown Form Based Zoning District and rezoning;
WHEREAS, before considering the creation of the Chapter 18.11, the rezoning of the Downtown Precise Plan area, the City Council reviewed and considered the potential environmental impacts of the Project and identified mitigation measures in the Environmental Impact Report for the Project (SCH#2022010282) (the “EIR”), in accordance Ordinance/Downtown Form-Based Zoning District Page 3 of 4 Rev: 09/2019
with the requirements of CEQA;
WHEREAS, the Project approvals will include a resolution certifying the EIR (the “CEQA Resolution”); a resolution approving the GPA (the “GPA Resolution”); a resolution approving the Downtown Precise Plan (the “Precise Plan Resolution”); and an ordinance (a) amending the Santa Clara City Code to include a new Chapter containing the zoning district relevant to the Downtown Precise Plan and (b) applying the new zoning designation across the Precise Area (the “Rezoning Ordinance”) (collectively, the “Approvals”); WHEREAS, notice of the public hearing on the proposed Project was published in the Santa Clara Weekly, a newspaper of general circulation for the City, on October 11, 2023; and
WHEREAS, on December 5, 2023, the City Council conducted a duly noticed public hearing to consider the new chapter of the zoning ordinance and corresponding rezoning of the downtown area, at which time interested persons were given an opportunity to give testimony and provide evidence in support of and in opposition to the proposed rezoning.

NOW THEREFORE, BE IT ORDAINED BY THE CITY OF SANTA CLARA AS FOLLOWS:

SECTION 1: That an new Chapter 18.11 entitled, “Regulations for the Downtown Form Based Zoning District”, is hereby added to Title 18 (entitled “Zoning”), of “The Code of the City of Santa Clara, California” (“SCCC”) as more specifically set forth in the “Downtown Form Based Zoning Code”, attached hereto and incorporated herein by this reference.

SECTION 2: That the City Council hereby amends the City of Santa Clara Zoning Map to apply the zoning designation contained in Chapter 18.11 to all properties in the Downtown Precise Plan Area, bounded by Benton Street to the north, Lafayette Street to the east, Homestead Road to the south, and Madison Street to the west.

Ordinance/Downtown Form-Based Zoning District Page 4 of 4 Rev: 09/2019
SECTION 3: That the City Clerk is authorized to renumber the new Chapter 18.11, or any section or subsection contained therein, in order to conform to the numbering system of the existing zoning ordinance, or any subsequent zoning ordinance adopted within twelve months following the Effective Date.

SECTION 4: Effective date. This ordinance shall take effect thirty (30) days after its final adoption; however, prior to its final adoption it shall be published in accordance with the requirements of Section 808 and 812 of “The Charter of the City of Santa Clara, California.” PASSED FOR THE PURPOSE OF PUBLICATION this 5
TH day of DECEMBER, 2023, by
the following vote:

AYES: COUNCILORS:

NOES: COUNCILORS:

ABSENT: COUNCILORS:

ABSTAINED: COUNCILORS:

ATTEST: ___________________________

NORA PIMENTEL, MMC

ASSISTANT CITY CLERK

CITY OF SANTA CLARA
Attachments incorporated by reference:

1. Downtown Form Based Zoning Code