VCE Board 2/10/2022 Meeting Slides-Materials — Valley Clean Energy Board of Directors, February 10, 2022

Valley Clean Energy Board Meeting – February 10, 2022
via video/teleconference
Item 13 – Carbon Neutral by 2030 Draft Report
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C
Zero-Carbon Portfolio
Construction:

Final Report
Valley Clean Energy Alliance
10 February 2022
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Table of Contents
• Project Deliverables
• Energeia Scope and Approach
• Estimate Future 8,760 Load
• Estimate Future Resource Costs
• Optimize Zero Carbon and Renewable Portfolios
• Key Risks
• Potential Pathways
• Appendices
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Deliverables, Scope and Approach
Project Deliverables
Scope
Approach
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Project Deliverables
• Develop a Portfolio Study Report per the matrix to the right in 2030 including:
○ Potential renewable resources and associated
capacities and costs
○ Risk analysis
○ Discussion of possible future industry trends in
renewable resources
Portfolio definitions include:
• Hour by Hour: Renewable or Carbon Free electricity is used to meet demand every hour of the day
Specified Analytical Framework
Source: VCE (2021), RFP NO. 2021CFPS
• Carbon Neutral: VCE’s carbon-emitting energy usage is offset by VCE’s annual renewable generation • Renewable Electricity: Includes biomass, solar thermal, photovoltaic, wind, geothermal, fuel cells using renewable fuels, small hydroelectric generation of 30 megawatts or less, digester gas, municipal solid waste conversion, landfill gas, ocean wave, ocean thermal, or tidal current and is assumed to be free of GHG emissions • Carbon Free Electricity: Identical to Renewable Electricity and includes large hydroelectric generation 7 © 2022 Energeia Pty Ltd. All Rights Reserved.

Overview of Energeia’s Scope and Approach
● Data Request
● Industry Trends
research
Information Discovery
1 Estimate
Future 8760
Net Load
2 Estimate
Future
Resource Costs
3 Optimise Zero
Carbon and
Renewable
Portfolios
4 ● IRP 8760 forecast
● Existing and planned
8760 resourcing
● Behind-the-Meter
(BTM) review
● Agree key risks and
sensitivities
● Validate with VCE
● Capital and operating
costs by technology
● Fuel and carbon
mitigation costs
● Agree key risks and
sensitivities
● Validate with VCE
● Identify least cost 8760
100% renewables and
zero carbon portfolios
● Identify least cost
annual 100%
renewables and zero
carbon portfolios
● Consider market
interactions
● Agree key risks and
sensitivities
● Validate with VCE
Asses Key
Risks and
Document
5 ● Develop Risk Report
● Develop Final Portfolio
Study Report
● Develop data pack
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Estimate Future 8760 Load
Develop 8760 Baseline Supplies
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2021 IRP (Energeia): Avg. Net Loads incl. PPAs
Source: VCE IRP (2020)
2030
• Table of assumed PPAs was provided by VCE and is included in the appendix
• Graphic showing load net of PPAs in 2020
○ No change from IRP as current for 2020
• By 2030, baseline contracts will increase the ‘Duck Curve’ significantly ○ VCE is mainly short resources before 5pm and after 4pm 2020
Source: VCE IRP (2020)
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0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Jan Feb Mar Apr May Jun
Jul Aug Sep Oct Nov Dec
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0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Jan Feb Mar Apr May Jun
Jul Aug Sep Oct Nov Dec
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Estimate Future Resource Costs
Future Industry Trends
Forecast Technology Costs
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Levelized Cost of Future Clean Resources
Source: NREL (2021), Annual Technology Baseline; Note: CSP = Concentrated Solar Power Thermal Technology Costs (incl. Fuel)
• Energeia completed a wide scan of potential utility
scale resources, which assessed advantages,
disadvantages, breakthrough potential, etc. by
technology
• Overall, major utility scale costs expected to
remaining relatively flat to 2050
○ Offshore wind, battery storage and hydrogen
costs expected to fall significantly in next 10
years
○ Other resource costs largely flat
RE Technology Costs
Source: NREL (2021), Annual Technology Baseline
Note: CCGT = Combined Cycle Gas Turbine, OCGT = Open Cycle Gas Turbine, CCS = Carbon Capture Sequestration; Capacity factors of 90% used for CCGT and 20% used for OCGT $0
$50
$100
$150
$200
$250
202120222023202420252026202720282029203020312032203320342035203620372038203920402041204220432044204520462047204820492050 LCOE ($/MWh)
Solar PV Wind - Onshore Hydro - River Geothermal
Solar Thermal (CSP) Wind - Offshore Hydro - Reservoir Biomass Storage Costs (excl. energy)
Source: NREL (2021), Annual Technology Baseline
Note: Li = Lithium, PHES = Pumped Hydro Energy Storage
$0
$50
$100
$150
$200
$250
$300
$350
$400
202120222023202420252026202720282029203020312032203320342035203620372038203920402041204220432044204520462047204820492050 $/MWh
CCGT - CCS CCGT - Hydrogen OCGT - Hydrogen
$0
$30
$60
$90
$120
$150
$180
202120222023202420252026202720282029203020312032203320342035203620372038203920402041204220432044204520462047204820492050 $/MWh
Li 2 hr Li 4 hr Li 6 hr Li 8 hr Li 10 hr PHES 12 hr
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Optimize Zero Carbon and Renewable
Portfolios
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Energeia’s Portfolio Optimization Model
• Energeia’s portfolio optimization tool was used to determine least cost resource portfolios • Key inputs include VCE’s 2030 hourly demand profiles, baseline capacity, and costs by resource type • Each portfolio scenario was parametrized to reflect the constraints, including risk scenarios • A non-linear solver was used to identify the least cost portfolio mix given all conditions ○ A key limitation of non-linear solvers is that there may be other, lower cost solutions due to the complexity of the system
○ Energeia undertook multiple runs to help mitigate this risk Portfolio Optimization Tool Diagram
8,760 Load Profiles
Incremental Resource
Costs
Unitized 8,760 Profiles by
Resource Category
Non-Linear
Solver
Load-Side Risk Impacts Scenario Parameters MWs by Resource and Cost Category
Capex and Opex by
Resource, Cost and
Revenue Category
Baseline Resource Portfolio 8,760 Profiles by Resource
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Optimized Resource Solutions by Portfolio
Source: Energeia research and analysis
Scenarios Power Source Solar Wind Geothermal Small
Hydro
Large
Hydro
4-Hour
BES
8-Hour
BES
12-Hour

PES OCGT
HBH Carbon Free 0.0 39.3 11.3 0.0 0.0 42.3 65.4 10.7 112.3 HBH Renewable 0.0 39.3 11.3 0.0 0.0 42.3 65.4 10.7 112.3 CN Carbon Free 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0
CN Renewable 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0
Proposed Portfolios (MW)
• Resource modelling found wind and geothermal to be the lowest cost resources for meeting all scenarios in 2030
• A green hydrogen fueled Open Cycle Gas Turbine is used in the hour-by-hour scenario to ensure load is met every hour at least cost1
• There is no difference between the portfolios using Carbon Free vs. Renewable electricity as hydropower is never the cheapest option with the prices being used 1 RNG was also considered as a fuel, but green hydrogen was used in the analysis because it is projected to be lower in cost after 2030 15 © 2022 Energeia Pty Ltd. All Rights Reserved.

Peak and Minimum Days
Source: VCE (2020), Energeia modelling; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine Hour-by-Hour – 2030 Minimum Day
Hour-by-Hour – 2030 Peak Day
Source: VCE (2020), Energeia modelling; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine Source: VCE (2020), Energeia modelling; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine
Carbon Neutral – 2030 Minimum Day
Carbon Neutral – 2030 Peak Day
Source: VCE (2020), Energeia modelling; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine -150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 kWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
-150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 kWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
-150
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-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 kWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
-150
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-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 kWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
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Annual Portfolio Costs
Source: Energeia research and analysis
Notes: HBH = Hour-by-Hour; CN = Carbon Neutral; Hydro = Hydropower; BES = Battery Energy Storage; PES = Pumped Energy Storage; OCGT = Open Cycle Gas Turbine Annual Total Portfolio Costs ($M/Yr)
Annual Resource Costs ($M/Yr)
Source: Energeia research and analysis
Notes: HBH = Hour-by-Hour; CN = Carbon Neutral; RA = Resource Adequacy; AS = Ancillary Services; FRA = Flexible Resource Adequacy; CAISO = CA Independent System Operator Scenarios Power Source Solar Wind Geo-thermal
Small
Hydro
Large
Hydro
4-Hour
BES
8-Hour
BES
12-Hour
PES OCGT Total ($M/Yr)
HBH Carbon Free $0.0 $3.3 $7.3 $0.0 $0.0 $5.3 $14.4 $3.3 $12.9 $46.5 HBH Renewable $0.0 $3.3 $7.3 $0.0 $0.0 $5.3 $14.4 $3.3 $12.9 $46.5 CN Carbon Free $0.0 $2.2 $0.0 $0.0 $0.0 $12.7 $1.7 $0.0 $0.0 $16.5 CN Renewable $0.0 $2.2 $0.0 $0.0 $0.0 $12.7 $1.7 $0.0 $0.0 $16.5 • The incremental resource portfolio to
meet hourly demand with zero carbon
generation is approximately three times
more costly at $46.5m compared to
$16.5m for a carbon neutral portfolio
○ These costs are in addition to VCE’s
current annual resource costs of
$50m to $60m
• Oversized resources in the HBH scenario
generate more CAISO revenue
Scenarios Power Source Resources RA/AS/
FRA CAISO Net
HBH Carbon Free $46.5 $0.0 ($3.9) $42.6
HBH Renewable $46.5 $0.0 ($3.9) $42.6
CN Carbon Free $16.5 $0.0 $0.5 $17.0
CN Renewable $16.5 $0.0 $0.5 $17.0
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Key Risks
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• Portfolio feasibility and cost risk factors were discussed with the working group, and a set of key risks agreed, which were then assessed against the optimized portfolios by scenarios o Risk of low rainfall
▪ Impact on hydro resources not modelled as no hydro resources included in optimal portfolio ▪ Impact on pumping loads tested using VCE data on pumping loads o Risk of resource availability for contracting
▪ Limited availability of geothermal, wind, etc. resources tested against California’s SB350 assumptions
▪ Green hydrogen-based combustion is an immature technology, impact of excluding it tested2 o Risk of CAISO prices being lower and even negative
▪ Impact of zero CAISO benefits tested
o Risk of programs impacting on portfolio costs
▪ Impact of higher-than-expected EV load tested
▪ Impact of higher-than-expected building electrification tested Key Risk Analysis
2 The hour-by-hour portfolio without green hydrogen-based combustion is $49.8m, which is $7.2m dollar more than the base hour-by-hour portfolio 19 © 2022 Energeia Pty Ltd. All Rights Reserved.

Annual Costs by Portfolio – Key Risk Factor Impacts
Source: Energeia research and analysis; Note: OCGT = Open Cycle Gas Turbine, EV = Electric Vehicle, BE = Building Electrification Carbon Neutral Balancing
• Added constraints generally increase portfolio costs
• The most expensive portfolio contains the most constraints:
○ No OCGT increases costs by $7.2M p.a.
○ No CAISO sales increases costs by $3.9M
• Some risk factors do not impact costs under this scenario as it does not incorporate hydropower or OCGT
○ CAISO sales assumed as a core part of the scenario
Hour-by-Hour Balancing
Source: Energeia research and analysis; Note: OCGT = Open Cycle Gas Turbine, EV = Electric Vehicle, BE = Building Electrification $42.6 $42.6
$49.8 $46.5
$55.6 $50.7 $49.1
$59.0
$0
$15
$30
$45
$60
$75
Base
No Hydropower
No OCGT
No CAISO Revenue
No OCGT,
No CAISO Revenue
Drought
EV Uptake
BE Uptake
$M/Yr
Series1
$17.0
$31.6
$22.5 $25.3
$0
$15
$30
$45
$60
$75
Base
No Hydropower
No OCGT
No CAISO Revenue
No OCGT,
No CAISO Revenue
Drought
EV Uptake
BE Uptake
$M/Yr
Series1
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Potential Pathways
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• Resources present in both portfolios should be purchased first. These resources include wind, 4-Hr BES and 8-Hr BES. • The costs of battery storage systems are expected to decline significantly over the next decade (Appendix A), while the costs of wind resources are projected to remain relatively stagnant, suggesting the optimal strategy is delaying purchases of BES. • Regarding resource placement, co-locating batteries at solar or wind sites, if possible, may minimize revenue lost to curtailment.

Pathways – Key Recommendations
Note: BES = Battery Energy Storage
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Appendix
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Background
Key CA CO2 Policies and
Targets
Key CCA, POU and IOU Trends
VCE Board Policies and Targets
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Background
• In 2018, the California Governor issued Executive Order B-55-181to Achieve Carbon Neutrality, which set a zero carbon goal by no later than 2045, and negative emissions thereafter, and the State Legislature passed Senate Bill No. 1002, requiring all electricity consumed in California to be 100% carbon neutral by 2045. • Since then, a growing number of California utilities have set more ambitious targets, including the Sacramento Municipal Utilities District (SMUD), whose Board approved3 a net zero carbon generation target by 2030, and the Los Angeles Department of Water and Power (LADWP), whose Board approved4 a net zero target by 2035. • California community choice aggregators (CCAs) are also increasingly setting carbon and/or renewable targets above those of state minimum levels, including San Jose Clean Energy’s goal of carbon neutrality by 2030, 17F 18F Peninsula Clean Energy’s goal of 100% renewable energy on a 24/7 basis by 202519F and finally, Marin Clean Energy’s goal of 85% renewable by 2029. • Valley Clean Energy (VCE) is in the process of reviewing its decarbonization pathways and engaged Energeia to analyze the feasibility, costs and benefits of pursuing renewable and carbon-free portfolios on an hour-by-hour and annual carbon neutral basis by 2030 to inform its Strategic Plan and Integrated Resource Plan (IRP). 1 State of California (2018), Executive Order B-55-18 To Achieve Carbon Neutrality 2 State of California – Legislative Information (2018), Senate Bill No. 100 3 SMUD (2021), Our 2030 Clean Energy Vision
4 Mayor of LA (2021), Targets – Renewable Energy
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Estimate Future 8760 Load
Average 8760 Load Profiles
VCE Power Purchase
Agreements
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2021 IRP (Energeia): Average Loads incl. DER
Source: VCE IRP (2020)
2030
• Charts are showing VCE load including DER and PPAs active in 2020 • Daily average loads net of load modifying Distributed Energy Resources (DER)
○ No change as current and correct as of 2020
• Behind the meter PV creating small Duck Curve by 2030 ○ This data will be updated in next IRP
2020
Source: VCE IRP (2020)
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0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Jan Feb Mar Apr May Jun
Jul Aug Sep Oct Nov Dec
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0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MWh
Jan Feb Mar Apr May Jun
Jul Aug Sep Oct Nov Dec
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Name of Counter Party Project Name Project Technology Solar (MW) Storage (MW) DR (MW) Geothermal (MW)
VCE
Allocation
Project Start
Year
Project Start
Month
PPA Term
(Years)
California Joint Powers
Authority Indian Valley Short Term PPA Hydroelectric Generation 2.9 100% 2020 May 5 Aquamarine Westside LLC PPA AC Solar PV 50 100% 2021 October 15 Putah Creek Solar Farms LLC Renewable PPA AC Solar PV 3 3 (4-hrs) 100% 2022 Jan 20 VESI 10 LLC Tierra Buena Energy Storage Lithium (RAR Attributes) 0 2.5 (4-hrs) 100% 2022 June 10 Leapfrog Power Inc. Resource Adequacy Agreement Demand Response (RAR Attributes) 0 0 7 100% 2021 June 10
Gibson Renewables LLC Renewable PPA Solar PV, Lithium Battery Storage 20 6.5 (4-hrs) 100% 2023 October 20
Resurgence Solar I, LLC Renewable PPA Solar PV AC Coupled w/ Li-Ion Storage 90 75 (4-hrs) 100% 2023 January 20
Willow Springs Solar 3 LLC Willow Springs Solar 3 Solar + Storage 72 36 (4-hrs) 100% 2024 January 15 Geothermal 15 100% 2026 20
Long-Duration Storage 5 (8-hrs) 100% 2026 15
Power Purchase Agreement Assumptions
Registered PPAs
Source: VCE
• All PPA’s loaded into the IRP tool are included in the table above • New CEC regulations require firm capacity from 5pm to 10pm to address Diablo replacement © 2022 Energeia Pty Ltd. All Rights Reserved.

Estimate Future Resource Costs
Low Carbon Fuel Price Forecast
Resource Research Results
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Green Hydrogen vs. Renewable Natural Gas
Forecasted Pricing
Source: American Gas Foundation (2019), Energeia research and analysis • The price of green hydrogen is forecasted to be lower than renewable natural gas after 2030, suggesting generation costs will be lower for turbines compatible with hydrogen • The prices are exclusive of any government incentives 2022 – 2040 Energy Prices
$0
$16
$32
$48
$64
$80
$96
$112
$128
2022202320242025202620272028202920302031203220332034203520362037203820392040 $/MWh
Renewable Natural Gas Green Hydrogen
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Key Future Zero Carbon Generation Technologies
Name Category Fuel Type Description Energy Efficiency Advantages Disadvantages Availability Potential Breakthroughs Thermal Generation Technologies
Combined Cycle
Turbine (CCGT) Combustion
Hydrogen /
Renewable Methane /
Methane + CCS
Generates power via combustion in a
combustion turbine followed by a
steam turbine to use waste heat
50-60%
• Higher efficiency than OCGT
• Mature technology
• Fuel flexible
• Provides inertia
• Higher capex than OCGT
• Emissions from combustion
• Less flexible than OCGT
• Limited availability of hydrogen or
renewable methane
• Pilot projects only
• Higher temp combustion turbine
Open Cycle Turbine
(OCGT) Combustion
Hydrogen /
Renewable Methane /
Methane + CCS
Generates power via combustion in a
gas turbine 30-40%
• Higher ramp rate than CCGT
• Mature technology
• Fuel flexible
• Provides inertia
• Lower capex than CCGT
• Lower efficiency than CCGT
• Emissions from combustion
• Less flexible than a OCGT
• Limited availability of hydrogen or
renewable methane
• Pilot projects only
• Higher temp combustion turbine
Carbon Capture and
Sequestration (CCS) Combustion Coal / Methane
Captures and stores CO2 from coal or
methane combustion to prevent it from
entering the atmosphere
80% • Allows use of relatively low-cost methane
and coal fuel
• Unproven technology
• Generates waste stream
• Commercially available
• Pilot projects only
• New electrochemical process converts
CO2 through a mineralization approach and
produces green hydrogen.

Small Modular
Reactor Fission Uranium Generates heat from fission, used to drive steam turbine 33-37% • Smaller (<300 MW) than conventional
nuclear (<1,600 MW)
• Lower and more stable fuel costs
compared to methane
• Relatively immature technology
• Potential community resistance • Pilot projects only • None identified Pebble Bed Reactor Fission Uranium Generates heat from fission, used to drive steam turbine Up to 50%
• Smaller (<300 MW) than conventional
nuclear (<1,600 MW)
• Lower and more stable fuel costs
compared to methane
• Fuel pebbles touted as inherently safe
• Relatively immature technology
• Potential community resistance • Pilot projects only • None identified Proton Exchange
Membrane Fuel Cell
(PEMFC)
Chemical Hydrogen Fuel cell generates electricity and water using hydrogen 30-50% • Higher ramp rate than SOFC• Maturing technology • Lower efficiency than SOFC
• Most only run on hydrogen
• Limited availability of hydrogen
• Pilot projects only
• DOE targeting higher efficiencies and
increased fuel stack hours
Solid Oxide Fuel Cell
(SOFC) Chemical Hydrogen / Renewable Methane
Fuel cell generates electricity and water
using hydrogen or methane 63-81% • Higher efficiency than PEMFC • Lower efficiency than SOFC
• Immature technology
• Less flexible than SOFC
• Limited availability of hydrogen
• Pilot projects only
• DOE targeting higher efficiencies and
increased fuel stack hours
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Key Future Renewable Energy Technologies
Name Category Capacity
Factor Description Advantages Disadvantages Availability Potential Breakthroughs Generation Technologies
Onshore Wind Wind 51% A windmill is used to turn a turbine to generate electricity on land
• Mature technology
• Relatively low $/kWh capex
• Relatively constant generation
• Community resistance
• Limited resource availability
• Commercially available
• Limited to areas of high wind resource
• Larger turbines increasing efficiency and
reducing costs
Offshore Wind Wind 40-50% Floating windmills are used to generate electricity in the ocean
• Mature technology
• Relatively low $/kWh capex
• Relatively constant generation
• Community resistance
• Limited resource availability
• Commercially available
• Limited to areas of high wind resource
• Limited to coast areas
• Larger turbines increasing efficiency and
reducing costs
Single Axis Solar
PV Solar 30-35% Photo-voltaic(PV) panels on a single axis tracking system are used to generate electricity • Mature technology
• Relatively low $/kWh capex
• Strongly seasonal
• Limited resource availability
• Commercially available
• Limited to areas of high solar resource
• Solar technology increasing efficiency and
lowering costs
Concentrated
Solar Power (CSP) Solar 25%
Mirrors are used to concentrate solar energy on a
working fluid, which is used to transfer heat to a
steam turbine
• Includes storage
• Firm capacity
• Relatively low $/kWh
• Strongly seasonal
• Limited resource availability
• Relatively immature
• Commercially available
• Limited to areas of high solar resource
• Pilot scale
• High temp steam turbines can reduce costs
Geothermal Geothermal 72% Underground geothermal energy is used to drive a steam turbine
• Relatively high capacity factor
• Firm capacity
• Mature technology
• Limited resource availability
• Relatively high $/kWh capex • Commercially available
• Limited to areas of high geothermal resource
Ocean Tidal Tidal 20-35% Tidal energy is used to drive an electric generator • Predictable resource • Complementary generation profile
• Requires tidal estuary
• Relatively expensive per kWh
• Immature technology
• Commercially available
• Limited to coastal areas
• Limited to tidal areas
Ocean Wave Wave 25-32% Wave energy is used to drive an electric generator • Predictable resource • Complementary generation profile
• Requires coast access
• Relatively expensive per kWh
• Immature technology
• Commercially available
• Limited to coastal areas
Run-of-River
Hydro Hydropower 40-80% Water flow is used to drive an electric generator • Relatively low $/kWh capex• Firm capacity • Community resistance
• Subject to rainfall
• Commercially available
• Limited to areas of high hydro potential
Reservoir Hydro Hydropower 35-43% Water is stored in dams and then released to drive an electric generator
• Relatively low $/kWh capex
• Includes storage
• Firm capacity
• Community resistance
• Subject to rainfall
• Subject to other uses, e.g. fish
• Commercially available
• Limited to areas of high hydro potential
Waste-to-Energy Waste 70% Methane is captured from waste and used to drive a combustion turbine
• Relatively low $/kWh cost
• Methane reduction boost
• Firm capacity
• Local emissions from combustion • Commercially available • Limited to areas with significant waste streams
Biomass Biomass 50-60% Methane is captured from biomass or biomass is burned directly to drive a combustion turbine • Firm capacity • Local emissions from combustion • Commercially available
• Limited to areas with significant biomass
streams
• Improvements in bio-digester technology
increases efficiency and reduces cost
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Key Future Storage Technologies
Name Cycle Time Description Round-trip
Losses Advantages Disadvantages Availability Potential Breakthroughs Storage Technologies
Capacitors Seconds Capacitors used to rapidly charge and discharge small amounts of electricity directly 5% • Fastest response of any technology• Mature technology • Relatively expensive per kWh
• Unable to store significant energy
• 10-20% losses per day
• Widely available
Flywheels Seconds Uses a flywheel to rapidly charge and discharge relatively small amounts of electricity using an electric generator 5%-50% • Relative fast response times• Mature technology • Relatively large footprint
• Relatively expensive per kWh
• 20-50% losses over 2 hours
• Widely available
Battery Hours Electrochemical reactions are used to store and discharge electricity directly 10%
• Relatively responsive
• Relatively low losses
• Mature technology
• Relatively high cost per kWh
• Thermal runaway • Widely available
• Metal air and liquid metal
formulations may improve cost
effectiveness
Flow Hours Stores electricity in two chemicals, which can be stored indefinitely 40% • No standing losses if turned off• Relatively safe • Unproven technology
• High parasitic losses while on
• Relatively high $/kWh
• Commercially available
• Pilot scale
CSP Hours Stores energy as heat in working fluid, which is then used to drive a heat recovery-based steam generator 1%
• Very low round trip losses
• Can be coupled with CSP
• Relatively low $/kWh capex
• Unproven technology
• Safety of high operating temp
• Commercially available
• Pilot scale
• High temp steam turbine
technology could increase efficiency,
lower $/kWh
Hydrogen-Compression Hours Uses steel or carbon fiber based receiving vessels to store relatively small amounts of hydrogen 53%
• Mature technology
• Relatively compact footprint
• Relatively low $/kWh capex
• Amount of space required
• High round trip losses • Widely available • Material science could reduce cost Hydrogen-Salt
Cavern Weeks Uses air compressors to store large amounts of hydrogen in salt caverns 42-55% • Relatively low cost per kWh• Mature technology • Requires access to a salt cavern
• High losses
• Relatively slow response
• Limited availability of salt caverns
Compressed Air
Energy Storage
(CAES)
Weeks CAES stores electricity in underground formations including salt caverns and an expander to drive a turbine generator 42-55% • Relatively low $/kWh capex• Mature technology • Requires access to a salt cavern
• High losses
• Relatively slow response
• Limited availability of salt caverns • Isobaric systems potentially reduce volume by 77%
Hydrogen-Organics Months Uses chemical processes to store hydrogen, typically as ammonia or methanol 59-89% • Mature technology• Relatively high energy density • Storage of volatile chemicals
• Relatively high losses
• Relatively high $/kWh
• Widely available • High potential for cost reduction
Pumped Hydro Months Pumps water into reservoirs for later use to drive water turbine generators 80%
• Mature technology
• Relatively low $/kWh capex
• Relatively low standing losses
• Requires access to reservoir
• Scale required
• Relatively slow response
• Limited availability of reservoirs
© 2022 Energeia Pty Ltd. All Rights Reserved.

Optimize Zero Carbon and Renewable
Portfolios
Summer and Winter Day
Annual Portfolio Costs
Scenario Configurations
Detailed Scenario Results
34 © 2022 Energeia Pty Ltd. All Rights Reserved.

Average Summer and Winter Days
Source: VCE (2020), Energeia modelling; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine
Hour-by-Hour – 2030 Average Winter Day
Hour-by-Hour – 2030 Average Summer Day
Source: VCE (2020), Energeia modelling; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine Source: VCE (2020), Energeia modelling; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine
Carbon Neutral – 2030 Average Winter Day
Carbon Neutral – 2030 Average Summer Day
Source: VCE (2020), Energeia modelling; Note: BES = Battery Energy Storage, PES = Pumped Energy Storage, DR = Demand Response, CHP = Combined Heat and Power, OCGT = Open Cycle Gas Turbine -150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 kWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
-150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 kWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
-150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 kWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
-150
-100
-50
0 50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 kWh
Solar Wind Geothermal 4-Hr BES
8-Hr BES 12-Hr PES DR CHP
OCGT Baseline Load Net Load
Seasons are based on PG&E’s electricity rates. Summer includes May to Oct, and Winter includes all other months. 35 © 2022 Energeia Pty Ltd. All Rights Reserved.

Annual Portfolio Costs – CASIO, RA, etc.

Source: Energeia research and analysis
Note: RA = Resource Adequacy; AS = Ancillary Services; RFA = Flexible Resource Adequacy Carbon Neutral Balancing
• The HBH portfolio supplies all needed Resource Adequacy (RA), Flexible RA and ancillary services requirements
• CAISO exports generate significant revenue, reducing costs by nearly 10%
• The CN portfolio also supplies all needed Resource Adequacy (RA), Flexible RA and ancillary services requirements
• CAISO grid purchases and sales almost perfectly offset under this scenario
Hour-by-Hour Balancing
Source: Energeia research and analysis
Note: RA = Resource Adequacy; AS = Ancillary Services; RFA = Flexible Resource Adequacy $46.5
$0.0
$42.6
-$3.93
$0
$7
$14
$21
$28
$35
$42
$49
Resources CAISO RA/AS/FRA Net
$M/Yr
Series2
$16.5
$0.0
$0.5 $17.0
$0
$7
$14
$21
$28
$35
$42
$49
Resources CAISO RA/AS/FRA Net
$M/Yr
Series2
36 © 2022 Energeia Pty Ltd. All Rights Reserved.

Scenario Configurations
• A wide number of scenarios
were assessed
• Scenarios 1, 2, 15 and 16 used to
assess key risk factors
• Greyed out permutations
considered infeasible
All Scenarios
Source: Energeia research and analysis
Notes: HBH = Hour-by-hour, CN = Carbon Neutral
# Scenario Electricity Type Summary Large Hydro Small Hydro OCGT CAISO Revenue
1 HBH Carbon Free P P P P
2 HBH Renewable O P P P
3 HBH Carbon Free No Hydro O O P P
4 HBH Renewable No Hydro O O P P
5 HBH Carbon Free No OCGT w/Green Hydrogen or RNG P P O P 6 HBH Renewable No OCGT w/Green Hydrogen or RNG O P O P 7 HBH Carbon Free No CAISO Revenue P P P O
8 HBH Renewable No CAISO Revenue O P P O
9 HBH Carbon Free No OCGT, No CAISO Revenue P P O O
10 HBH Renewable No OCGT, No CAISO Revenue O P O O
11 HBH Carbon Free No Hydro, No OCGT O O O P
12 HBH Renewable No Hydro, No OCGT O O O P
13 HBH Carbon Free No Hydro, No OCGT, No CAISO Revenue O O O O 14 HBH Renewable No Hydro, No OCGT, No CAISO Revenue O O O O 15 CN Carbon Free P P P P
16 CN Renewable O P P P
17 CN Carbon Free No Hydro O O P P
18 CN Renewable No Hydro O O P P
19 CN Carbon Free No OCGT w/Green Hydrogen or RNG P P O P 20 CN Renewable No OCGT w/Green Hydrogen or RNG O P O P 21 CN Carbon Free No CAISO Revenue P P P O
22 CN Renewable No CAISO Revenue O P P O
23 CN Carbon Free No OCGT, No CAISO Revenue P P O O
24 CN Renewable No OCGT, No CAISO Revenue O P O O
25 CN Carbon Free No Hydro, No OCGT O O O P
26 CN Renewable No Hydro, No OCGT O O O P
27 CN Carbon Free No Hydro, No OCGT, No CAISO Revenue O O O O 28 CN Renewable No Hydro, No OCGT, No CAISO Revenue O O O O Grey = Not Valid
37 © 2022 Energeia Pty Ltd. All Rights Reserved.

Detailed Scenario Results (1/3)
• All key data shown
Name Plate Capacity (MW)
Source: Energeia research and analysis
Notes: HBH = Hour-by-hour, CN = Carbon Neutral
# Scenario Electricity Type Scenario Summary Solar Wind Geother-mal Small Hydro Large Hydro 4-Hour BES
8-Hour
BES
12-Hour

PES OCGT
1 HBH Carbon Free 0.0 39.3 11.3 0.0 0.0 42.3 65.4 10.6 112.3 2 HBH Renewable 0.0 39.3 11.3 0.0 0.0 42.3 65.4 10.6 112.3 3 HBH Carbon Free No Hydro
4 HBH Renewable No Hydro 0.0 39.3 11.3 0.0 0.0 42.3 65.4 10.6 112.3 5 HBH Carbon Free No OCGT 0.0 28.4 29.1 0.0 0.0 83.5 74.3 24.2 0.0 6 HBH Renewable No OCGT 0.0 28.4 29.1 0.0 0.0 83.5 74.3 24.2 0.0 7 HBH Carbon Free No CAISO Revenue 0.0 39.3 11.3 0.0 0.0 42.3 65.4 10.6 112.3 8 HBH Renewable No CAISO Revenue 0.0 39.3 11.3 0.0 0.0 42.3 65.4 10.6 112.3 9 HBH Carbon Free No OCGT, No CAISO Revenue 0.0 28.4 29.1 0.0 0.0 83.5 74.3 24.2 0.0 10 HBH Renewable No OCGT, No CAISO Revenue 0.0 28.4 29.1 0.0 0.0 83.5 74.3 24.2 0.0 11 HBH Carbon Free No Hydro, No OCGT
12 HBH Renewable No Hydro, No OCGT 0.0 28.4 29.1 0.0 0.0 83.5 74.3 24.2 0.0 13 HBH Carbon Free No Hydro, No OCGT, No CAISO Revenue
14 HBH Renewable No Hydro, No OCGT, No CAISO Revenue 0.0 28.4 29.1 0.0 0.0 83.5 74.3 24.2 0.0 15 CN Carbon Free 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0 16 CN Renewable 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0
17 CN Carbon Free No Hydro
18 CN Renewable No Hydro 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0 19 CN Carbon Free No OCGT 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0 20 CN Renewable No OCGT 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0 21 CN Carbon Free No CAISO Revenue
22 CN Renewable No CAISO Revenue
23 CN Carbon Free No OCGT, No CAISO Revenue
24 CN Renewable No OCGT, No CAISO Revenue
25 CN Carbon Free No Hydro, No OCGT
26 CN Renewable No Hydro, No OCGT 0.0 26.1 0.0 0.0 0.0 100.0 7.7 0.0 0.0 27 CN Carbon Free No Hydro, No OCGT, No CAISO Revenue
28 CN Renewable No Hydro, No OCGT, No CAISO Revenue
38 © 2022 Energeia Pty Ltd. All Rights Reserved.

Detailed Scenario Results (2/3)
• All key data shown
Costs by Resource ($M/Yr)
Source: Energeia research and analysis
Notes: HBH = Hour-by-hour, CN = Carbon Neutral
# Scenario Electricity Type Scenario Summary Solar Wind Geother-mal Small Hydro Large Hydro 4-Hour BES
8-Hour
BES
12-Hour

PES OCGT
1 HBH Carbon Free $0.0 $3.3 $7.3 $0.0 $0.0 $5.3 $14.4 $3.3 $12.9 2 HBH Renewable $0.0 $3.3 $7.3 $0.0 $0.0 $5.3 $14.4 $3.3 $12.9 3 HBH Carbon Free No Hydro
4 HBH Renewable No Hydro $0.0 $3.3 $7.3 $0.0 $0.0 $5.3 $14.4 $3.3 $12.9 5 HBH Carbon Free No OCGT $0.0 $2.4 $18.8 $0.0 $0.0 $10.6 $16.4 $7.5 $0.0 6 HBH Renewable No OCGT $0.0 $2.4 $18.8 $0.0 $0.0 $10.6 $16.4 $7.5 $0.0 7 HBH Carbon Free No CAISO Revenue $0.0 $3.3 $7.3 $0.0 $0.0 $5.3 $14.4 $3.3 $12.9 8 HBH Renewable No CAISO Revenue $0.0 $3.3 $7.3 $0.0 $0.0 $5.3 $14.4 $3.3 $12.9 9 HBH Carbon Free No OCGT, No CAISO Revenue $0.0 $2.4 $18.8 $0.0 $0.0 $10.6 $16.4 $7.5 $0.0 10 HBH Renewable No OCGT, No CAISO Revenue $0.0 $2.4 $18.8 $0.0 $0.0 $10.6 $16.4 $7.5 $0.0 11 HBH Carbon Free No Hydro, No OCGT
12 HBH Renewable No Hydro, No OCGT $0.0 $2.4 $18.8 $0.0 $0.0 $10.6 $16.4 $7.5 $0.0 13 HBH Carbon Free No Hydro, No OCGT, No CAISO Revenue
14 HBH Renewable No Hydro, No OCGT, No CAISO Revenue $0.0 $2.4 $18.8 $0.0 $0.0 $10.6 $16.4 $7.5 $0.0 15 CN Carbon Free $0.0 $2.2 $0.0 $0.0 $0.0 $12.7 $1.7 $0.0 $0.0 16 CN Renewable $0.0 $2.2 $0.0 $0.0 $0.0 $12.7 $1.7 $0.0 $0.0 17 CN Carbon Free No Hydro
18 CN Renewable No Hydro $0.0 $2.2 $0.0 $0.0 $0.0 $12.7 $1.7 $0.0 $0.0 19 CN Carbon Free No OCGT $0.0 $2.2 $0.0 $0.0 $0.0 $12.7 $1.7 $0.0 $0.0 20 CN Renewable No OCGT $0.0 $2.2 $0.0 $0.0 $0.0 $12.7 $1.7 $0.0 $0.0 21 CN Carbon Free No CAISO Revenue
22 CN Renewable No CAISO Revenue
23 CN Carbon Free No OCGT, No CAISO Revenue
24 CN Renewable No OCGT, No CAISO Revenue
25 CN Carbon Free No Hydro, No OCGT
26 CN Renewable No Hydro, No OCGT $0.0 $2.2 $0.0 $0.0 $0.0 $12.7 $1.7 $0.0 $0.0 27 CN Carbon Free No Hydro, No OCGT, No CAISO Revenue
28 CN Renewable No Hydro, No OCGT, No CAISO Revenue
39 © 2022 Energeia Pty Ltd. All Rights Reserved.

Detailed Scenario Results (3/3)
• All key data shown
Totals ($M/Yr)
Source: Energeia research and analysis
Notes: HBH = Hour-by-hour, CN = Carbon Neutral
# Scenario Electricity Type Scenario Summary Resources RA/AS/FRA CAISO Net 1 HBH Carbon Free $46.5 $0.0 -$3.9 $42.6
2 HBH Renewable $46.5 $0.0 -$3.9 $42.6
3 HBH Carbon Free No Hydro
4 HBH Renewable No Hydro $46.5 $0.0 -$3.9 $42.6
5 HBH Carbon Free No OCGT $55.6 $0.0 -$5.8 $49.8
6 HBH Renewable No OCGT $55.6 $0.0 -$5.8 $49.8
7 HBH Carbon Free No CAISO Revenue $46.5 $0.0 $0.0 $46.5 8 HBH Renewable No CAISO Revenue $46.5 $0.0 $0.0 $46.5
9 HBH Carbon Free No OCGT, No CAISO Revenue $55.6 $0.0 $0.0 $55.6 10 HBH Renewable No OCGT, No CAISO Revenue $55.6 $0.0 $0.0 $55.6 11 HBH Carbon Free No Hydro, No OCGT
12 HBH Renewable No Hydro, No OCGT $55.6 $0.0 -$5.8 $49.8 13 HBH Carbon Free No Hydro, No OCGT, No CAISO Revenue
14 HBH Renewable No Hydro, No OCGT, No CAISO Revenue $55.6 $0.0 $0.0 $55.6 15 CN Carbon Free $16.5 $0.0 $0.5 $17.0
16 CN Renewable $16.5 $0.0 $0.5 $17.0
17 CN Carbon Free No Hydro
18 CN Renewable No Hydro $16.5 $0.0 $0.5 $17.0
19 CN Carbon Free No OCGT $16.5 $0.0 $0.5 $17.0
20 CN Renewable No OCGT $16.5 $0.0 $0.5 $17.0
21 CN Carbon Free No CAISO Revenue
22 CN Renewable No CAISO Revenue
23 CN Carbon Free No OCGT, No CAISO Revenue
24 CN Renewable No OCGT, No CAISO Revenue
25 CN Carbon Free No Hydro, No OCGT
26 CN Renewable No Hydro, No OCGT $16.5 $0.0 $0.5 $17.0 27 CN Carbon Free No Hydro, No OCGT, No CAISO Revenue
28 CN Renewable No Hydro, No OCGT, No CAISO Revenue
© 2022 Energeia Pty Ltd. All Rights Reserved.

Energeia USA
Overview
Relevant Experience
41 © 2022 Energeia Pty Ltd. All Rights Reserved.

Introduction to Energeia
• Offices in Davis, California and Sydney, Australia
• Eight full-time experts with renewable energy industry experience • Backgrounds in economics, science, engineering and marketing Energeia US Team
Energeia US Headquarters in Davis, CA
Mustafa
Edrees
Taylor
Nguyen
Min
Kyaw
Yoana
Battraw
42 © 2022 Energeia Pty Ltd. All Rights Reserved.

Energeia’s Relevant Experience
Client Project Relevant Experience
Sacramento Municipal
Utilities District Alternative Fuels Assessment
Energeia was engaged to perform an alternative fuels assessment to identify optimal low cost, low carbon fuels for retooling of five aeroderivative LM6000 engines. Energeia performed wheel to well analyses of multiple pathways for renewable gas production and ultimately identified multiple key pathways for SMUD to pursue to decarbonize their peaker plants.

Sacramento Municipal
Utilities District
Integrated Distributed
Resource Plan
Energeia used its in-house utility simulator tool, uSim, to determine the distribution system impacts and associated costs and benefits of DERs as envisioned in the Sacramento Municipal Utility District’s 2018 Integrated Resources Plan.

Energeia also estimated DER values as avoided distribution capital and O&M for distribution.

The City of Davis Climate Action and
Adaption Plan Analysis
Energeia is part of the team assessing the Davis CAAP through analysis of vehicle and building electrification, rooftop PV and energy efficiency opportunities and the associated costs and benefits. This project involves modelling of all connection points and vehicles in Davis.

Orlando Utilities
Commission
Battery Valuation and
Framework
Energeia developed a production cost and capacity expansion tool to support OUC’s evaluation of future battery energy storage projects. We defined the key value streams and methodologies to quantify monetary and non-monetary benefits as they apply to OUC and the Florida Municipal Power Pool (FMPP) and identified the key use cases for battery storage for value stacking.

Los Angeles Department of
Water and Power
Once Through Cooling
Reliability Study
Energeia developed specific, reliable, implementable, practical and least cost DER solutions tailored to address LADWP’s forecast system constraints expected to arise under a range of alternative 1.5 GW thermal generation plant repowering scenarios, including a no repowering scenario.

Los Angeles Department of
Water and Power
Distributed Energy Resources
Integration Study
Energeia analyzed LADWP’s cost-of-service at the system, transmission, 34.5kV and 4.8kV level, and by time period, to identify optimized DER programs, incentives and cost-reflective rate design for delivery of optimized DER adoption patterns and minimization of LADWP’s overall cost-of-service and customer electricity costs Energeia USA Pty Ltd
132 E Street
Suite 310
Davis, CA 95616
P +1 (530) 302 3861
[email protected].
energeia-usa.com
Thank You
Valley Clean Energy Board Meeting – February 10, 2022
via video/teleconference
Item 14 – CC Power Long Duration Storage (LDS): Tumbleweed Project 44 yvonnehunterphotography.com
Public Comments
45 To Provide Public Comment on any agenda item please:
➢ E-mail 300 words or less to: [email protected] OR
Join the Public Comment Queue by
➢ “Raising Hand” on Zoom Meeting
OR
➢ Press *9 if joining by phone
Emailed comments received before the item has concluded will be read into the record.

Emailed comments received after the item has concluded but before the end of the meeting will not be read but will be included in the meeting record.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)]

1. Long Duration Storage Procurement Goals

2. CPUC Mid-term Reliability Procurement Order

3. LS Power Tumbleweed Project Overview

4. CC Power Participating Members

5. Allocations and Authority

6. Contract Structure

7. Conclusion
46 Item 14 – CC Power LDS Tumbleweed Project: Overview
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] • Enhance portfolio value via cost-effective resources: value of energy + capacity > costs • Integrate intermittent resources (solar + wind)
• Support grid reliability
• Share development and project performance risk via new joint powers agency → California Community Power (CC Power)
• “Right-size” project subscription
• Meet potential CPUC procurement mandates
47 Item 14 – CC Power LDS Tumbleweed Project: LDS Joint Procurement Goals
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] • LSEs required to collectively procure 11,500 MW net qualifying capacity (NQC) of new resources
• Follow-on to November 7, 2019 CPUC decision mandating 3,300 MW NQC procurement for 2021-2023 to maintain reliability
• Contract of at least 10 years
• Allocated to LSEs by load share
• Resources must be zero-emission or RPS eligible (no fossil resources) • 4,500 MW of obligation subject to specific category requirements 48 Item 14 – CC Power LDS Tumbleweed Project: Mid-term Reliability Procurement Order (MTR)
D.21-06-035 adopted by CPUC on June 24, 2021 to address mid-term reliability Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 49 Item 14 – CC Power LDS Tumbleweed Project: Procurement Order Timing
Procurement Category 2023 2024 2025 2026 Total
Zero-emissions generation, generation paired with
storage, or demand response resources - - 2,500 - 2,500 Firm zero-emitting resources - - - 1,000 1,000
Long-duration storage resources - - - 1,000 1,000
Remaining New Capacity Required - - 7,000
Total Annual Capacity Requirements 2,000 6,000 1,500 2,000 11,500 Procurement Obligation in NQC (MW) for All LSEs by Category and Year 1,000 MW of LDS ordered by CPUC
• Technology agnostic
• 8-hour minimum discharge duration
• COD June 2026 – demonstrate reasonable effort by February 2023 • 10-year minimum term
• Subject to Effective Load Carrying Capability (ELCC) adjustments Procurement Category 2023 2024 2025
Indicative
2026
Indicative
4-Hour Battery 96.3% 90.7% 74.2% 69.0%
6-Hour Battery 98.0% 93.4% 79.6% 75.1%
8-Hour Battery 98.2% 94.3% 82.2% 78.2%
8-Hour Pumped Storage Hydro 76.8%
12-Hour Pumped Storage Hydro 80.8%
CPUC Interim ELCCs
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 50 Item 14 – CC Power LDS Tumbleweed Project: Project Overview Tumbleweed was the highest-ranking LDS project
• Developer – LS Power
• Technology –Lithium-ion, 8 hours discharge duration
• Project size - 69 MW/552 MWh
• Product – Tolling Agreement w/full capacity rights
• Location – Rosamond, Kern County
• COD – Q2 2026
• Price - fixed $/kw-mo, no escalation
• Term – 15 years
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 51 Item 14 – CC Power LDS Tumbleweed Project: Member Participation 7 CCAs agreed to move forward with joint LDS procurement for Tumbleweed
• MTR LDS procurement mandate for the 7 CCAs is 96.5 MW • 123.4 MW adjusted by ELCC
• Tumbleweed is 69 MW nameplate – meeting 56% of ELCC adjusted need under the MTR • Capacity to be allocated based on MTR share obligation Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 52 Item 14 – CC Power LDS Tumbleweed Project: Allocations & Authority Each CCA will seek their respective governing body authority to participate • Initial expected share based on MTR obligation
• Minimum authority needs to cover:
1) contingency risk of one or more CCA’s not executing and 2) 25% step-up cap due to default
• Maximum authority will be based on individual CCA’s appetite to take additional volume CCA % Entitlement Share Intitial Entitlement
Share MW
Minimum Authority to
Seek MW
CPSF 16.06% 11.08 16.94
PCE 19.69% 13.59 20.77
RCEA 3.62% 2.50 3.82
SJCE 22.28% 15.37 23.50
SVCE 21.25% 14.66 22.41
SCPA 12.95% 8.94 13.66
VCE 4.15% 2.86 4.38
Total 100.00% 69
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 53 Item 14 – CC Power LDS Tumbleweed Project: Contract Structure Energy Storage Services Agreement Project Participation Share Agreement LDS Project CCA Customers
(Each participating CCA executes with Developer’s Seller entity and CC Power) Buyer Liability Pass Through Agreements
Operations Agreement Scheduling
Coordinator
Agreement
VCE to execute the PPSA and the BLPTA (the Operating Agreement will be signed at a later date) Developer CC Power CC Power 7 CCAs
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] • Tumbleweed was selected through a robust and competitive solicitation process • Tumbleweed net present value (NPV) to participating CCAs is highly uncertain • Project is expected to include project labor agreement • Contracting Structure includes a “step-up” provision which exposes VCE to taking up to 25% additional capacity (based on contract share)
• Procurement of Long Duration Storage (8-hours or more) is mandated through MTR order • VCE’s expected share of Tumbleweed is 2.86 MW (56% of obligation) • Need approx. 2.5 MW of additional LDS - remaining shortlisted projects may meet or exceed remaining needs1
54 Item 14 – CC Power LDS Tumbleweed Project: Conclusion VCE must procure ~5 MW of qualifying LDS to meet MTR
1) Additional need is to satisfy CPUC mandates. Per the Carbon Neutral study VCE has a need beyond the mandate which can be procured at a later date.

Valley Clean Energy Board Meeting – February 10, 2022
via video/teleconference
Item 15 – 2022 Customer Rates
55 yvonnehunterphotography.com
Public Comments
56 To Provide Public Comment on any agenda item please:
➢ E-mail 300 words or less to: [email protected] OR
Join the Public Comment Queue by
➢ “Raising Hand” on Zoom Meeting
OR
➢ Press *9 if joining by phone
Emailed comments received before the item has concluded will be read into the record.

Emailed comments received after the item has concluded but before the end of the meeting will not be read but will be included in the meeting record.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 57 Item 15 – 2022 Customer Rates
Overview
• Background
• 2022 Customer Rate Scenarios
• Customer Outreach
• Recommendation
• Discussion
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 58 Item 15 – 2022 Customer Rates
Background
• All electric utilities develop forecasts based upon informed technical estimates. These forecasts incorporate factors such as future weather, load, market power prices, and other business conditions. Actual outcomes inevitably vary and in extreme instances, outcomes may vary significantly.
• Primary financial drivers remain the same included in FY 2021/22 budget adoption • Power market costs continuing to increase above forecast in 2021 • 2021 PCIA remaining high into early 2022
• Delayed 2022 PG&E Bundled Rate changes
• Error in financial estimations overvalued positive impacts of VCE’s long-term PPA’s • 2023 Short-term outlook: continued volatility with PG&E PCIA rates and generation rates. • Longer-term outlook (2024+): increased stability and cost certainty due to long-term PPA’s and cost-recovery rate structure.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 59 Item 15 – 2022 Customer Rates
Background (continued)
• November 8th PG&E filed a November update for its 2022 Power Charge Indifference Adjustment (PCIA) and Generation Rates
• November 10th VCE Board adopted cost-based rate policy and deferred consideration of an expanded customer rate structure
• The cost-based rate setting approach is designed to meet VCE’s annual expenditures and build long-term fiscal stability through the establishment and maintenance of reserves. • January 20, 2022 CAC Recommended Rates and Implementing Procedure • January 24, 2022 CPUC proposed decision (PD) filed.
• 2022 PCIA set to decrease 57%
• 2022 PG&E’s average generation rates set to increase by 33% • All rate changes are inclusive of PG&E December actuals Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 60 Item 15 – 2022 Customer Rates
2022 Customer Rate & Budget Scenarios
Using the information from CPUC proposed decision on January 24, 2022, staff conducted a financial analysis that included three rate scenarios:

1. Scenario 1 (Low Income/At-Risk* Credit): 2.5% rate credit (Approx. $750k) for CARE/FERA customers; all other revenues directed to reserves.

2. Scenario 2 (Base Case): no modifications; all revenues directed to reserves.

3. Scenario 3 (Low Income/At-Risk* + Credit): 3.5% rate credit (Approx $1M) for CARE/FERA customers plus 1% rate credit (Approx. $750k) for other customers; all other revenues directed to reserves.
*Includes CARE/FERA and Medical Baseline customers
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 61 Item 15 – 2022 Customer Rates
Updated Customer Rate & Budget Scenarios - Staff’s recommendation – Scenario 1 Scenario 1 FY2019 FY2020 FY2021 FY2022 CY2022 CY2023 CY2024 CY2025 Revenue 51,035 55,249 54,657 29,677 89,750 69,500 70,750 71,050 Power Cost 38,540 41,538 54,234 30,133 66,990 52,400 47,100 48,400 Other Expenses 3,850 4,346 4,267 2,276 5,292 5,398 5,506 5,616 Net Income 8,646 9,365 (3,844) (2,732) 17,468 11,702 18,144 17,034 Scenario 2 FY2019 FY2020 FY2021 FY2022 CY2022 CY2023 CY2024 CY2025 Revenue 51,035 55,249 54,657 29,677 90,500 70,250 71,500 71,800 Power Cost 38,540 41,538 54,234 30,133 66,990 52,400 47,100 48,400 Other Expenses 3,850 4,346 4,267 2,276 5,292 5,398 5,506 5,616 Net Income 8,646 9,365 (3,844) (2,732) 18,218 12,452 18,894 17,784 Scenario 3 FY2019 FY2020 FY2021 FY2022 CY2022 CY2023 CY2024 CY2025 Revenue 51,035 55,249 54,657 29,677 89,000 68,750 70,000 70,300 Power Cost 38,540 41,538 54,234 30,133 66,990 52,400 47,100 48,400 Other Expenses 3,850 4,346 4,267 2,276 5,292 5,398 5,506 5,616 Net Income 8,646 9,365 (3,844) (2,732) 16,718 10,952 17,394 16,284 Actual YTD
(6 Month)
Budget
Actuals Scenarios Preliminary Forecast*
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 62 Item 15 – 2022 Customer Rates
Estimates of Rate Effect on Average Customer Classes (total electricity bill) Customer Class Residential Small
Commercial
Med
Commercial
Large
Commercial* Ag
Current Annual Bill $1,860/yr $ 4,500/yr $ 55,200/yr $ 98,400/yr $ 21,600/yr Current Monthly
Bill $155/mo $ 400/mo $4,600/mo $ 8,200/mo $ 1,800/mo
Monthly Impact of
12% total Elec. Bill
(33% adj. on
Generation)
Approx.
$19/mo
Approx.
$48/mo
Approx.
$745/mo**
Approx.
$1,221/mo**
Approx.
$ 214/mo
Notes:

CARE customers total elec. bill reduced by approximately 35%; FERA by 18%. * Large Commercial does not include the less than 10 largest commercial customers (E-19 and E-20) as it would be a non-representative average for the majority of large commercial customers. The average monthly impact for E-19 and E-20 customers would be approximately $830 based on an average monthly bill of approximately $34,500. ** Medium and Large Commercial rates include the limited portion of the demand charges on the generation portion of the bill, resulting in approximate 0.5% higher increases.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 63 Item 15 – 2022 Customer Rates
Financial Reserves Target
Staff is seeking feedback on VCE setting rates for 2022 at a level that will fully fund the 2022 budget and build back reserves that have been used over the past 18 months to stabilize customer rates
• Staff’s recommendation is that VCE establish a minimum target of 80-90 days cash reserve by the end of 2022 which would provide two key benefits:
(1) increased financial stability while taking a significant step toward establishing an investment grade credit rating
(2) preparing for future PCIA and power market volatility Note: staff will be bringing back a financial reserve policy update later in 2022 for Board consideration.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 64 Item 15 – 2022 Customer Rates
Customer Outreach & Communications
VCE continues a measured, transparent customer outreach strategy with an emphasis on VCE’s additional benefits such as more choice in electricity supply, local control, and community reinvestment through energy contracts and programs.

Based on VCE matching PG&E rates and other CCAs undertaking similar rate actions, staff does not anticipate significant opt-out customer activity in response to the rate changes.

VCE will continue to monitor customer activity as the rates are implemented for possible adjustments.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 65 Item 15 – 2022 Customer Rates
Recommendation

1. Approve VCE 2022 Customer Rates (Scenario 1):
a. Customer rates for 2022 to match PG&E 2022 generation rates for all customer classes.
b. A rate credit of 2.5% for CARE and FERA customers in 2022

2. Conduct a mid-year rates review in Q2 2022 to assess rates forecast and determine the feasibility of:
a. allocating additional funds for 2022 clean energy content procurement b. allocating additional funds to program implementation c. providing additional rate credits for all customer classes during peak summer months in 2022.

3. Direct Staff to continue to develop and evaluate the feasibility of a revised rate structure with three customer options: (1) Standard Green (default) and (2) UltraGreen (100% renewable) with cost-based rates and adding a (3) least-cost customer rate option.

Valley Clean Energy Board Meeting – February 10, 2022
via video/teleconference
Item 16 – 2022 Budget
66 yvonnehunterphotography.com
Public Comments
67 To Provide Public Comment on any agenda item please:
➢ E-mail 300 words or less to: [email protected] OR
Join the Public Comment Queue by
➢ “Raising Hand” on Zoom Meeting
OR
➢ Press *9 if joining by phone
Emailed comments received before the item has concluded will be read into the record.

Emailed comments received after the item has concluded but before the end of the meeting will not be read but will be included in the meeting record.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 68 Item 16 – VCE 2022 Budget
Overview
• Background of Budget Development
• Updated FY 2021-22 (6-month) Financials
• Key factors Influencing VCE 2022 Budget
• 2022 Budget Scenarios
• Scenario 1 (Low Income/At-Risk* Credit): 2.5% rate credit for CARE/FERA customers • Scenario 2 (Base Case): All revenues directed to reserves. • Scenario 3 (Low Income/At-Risk* + Credit): 3.5% rate credit for CARE/FERA customers plus 1% rate credit for other customers
• Recommendation
• Discussion
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 69 Item 16 – VCE 2022 Budget
Background
VCE has taken key actions leading up to the CY2022 budget adoption. • June 2020 - FY 2020-21 Budget adoption with fiscal mitigation policy adjustments • October 2020 - FY 2020-21 Mid-year budget update to monitor Pandemic Impacts • May 2021 – FY 2021-22 Budget update with load update. • June 2021 – FY 2021-22 Budget adoption with extended fiscal mitigation policy • October 2021 – Budget update with power costs and financial model corrections. • October 2021 – Board adopted rate increase to preserve cash reserves. • November 2021- VCE Board adopted cost-based rate policy and deferred consideration of an expanded customer rate structure
• The cost-based rate setting approach is designed to meet VCE’s annual expenditures and build long-term fiscal stability through the establishment and maintenance of reserves. • November 2021 – Adopted change from fiscal year to calendar year.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 70 Item 16 – VCE 2022 Budget
FY 2021-22 Variance
Revenue $ 24,737 $ 29,677 $ 4,940
Power Cost $ 27,446 $ 30,133 $ (2,687)
Other Expenses $ 2,509 $ 2,276 $ 233
Net Income $ (5,218) $ (2,732) $ 2,486

APPROVED
BUDGET FY 2021
(6 MO)
Actual YTD
Dec. 31, 2022
(6 MO)
• Customer Rate Increase of 2% - The Board approved an accelerated rate adjustment of approximately 2% on the average customer bill in mid-October for $400K.
• Power Prices. Average forward market power prices have increased 57% since May 2021. The increased market price compared to contracted power purchase agreements and hedged power contract prices resulted in an offset for additional load requirements during peak season. • Programs Costs, Regulatory Analyst role (Part-time), and contingency were budgeted for the entire fiscal year and not utilized during the first six months.

Current FY Update – FY 2021-22 (6 Month) unaudited
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 71 Item 16 – VCE 2022 Budget
Key Factors influencing the VCE 2022 Budget
• Power Prices. Average forward market power prices increased by 57% (April-21) • PG&E Rate Adjustments – Delays in annual rate setting. PG&E's current filings/CPUC proposed decision effective March 1st, 2022 (33% rate increase and a PCIA reduction of 57%)
• Financial Power Cost Model - Corrected forecast was approximately $13M over the three FYs 2022 to 2024
• PCIA. A net 46% increase in the PCIA from 2020/21 continued into 2022 due to delays in CPUC ERRA proceeding.
• Calendar Year Budget - Budget adoption process was shifted from fiscal year to avoid overlap with the annual load forecast updates and the beginning of the hedging process
• Long-Term Power Purchase Agreements starting in 2021 through 2024.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 72 Item 16 – VCE 2022 Budget
• Contracted long-term PPAs
began in 2021
• 80%+ of VCE’s annual load
by 2024
• Reduced VCE costs
compared to current RPS
and RA market costs
• Significantly reduce
volatility as VCE moves
forward (smaller open position)
Long-term Fixed Price Power Purchase Agreements
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 73 Item 16 – VCE 2022 Budget
VCE 2022 Budget Scenarios
Using the information from CPUC proposed decision on January 24, 2022, staff conducted a financial analysis that included three rate scenarios:

1. Scenario 1 – Staff Recommendations (Low Income/At-Risk* Credit): 2.5% rate credit for CARE/FERA customers; all other revenues directed to reserves. (~85 days cash reserves by end of 2022)

2. Scenario 2 (Base Case): no modifications; all revenues directed to reserves. (~90 days cash reserves by end of 2022)

3. Scenario 3 (Low Income/At-Risk* + Credit): 3.5% rate credit for CARE/FERA customers plus 1% rate credit for other customers; all other revenues directed to reserves. (~80 days cash reserves by end of 2022)
*Includes CARE/FERA and Medical Baseline customers
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 74 Item 16 – VCE 2022 Budget
VCE 2022 Budget Scenarios
VCE budget Scenarios for 2022 build back reserves that have been used over the past 18 months to stabilize customer rates and provide a level of financial relief to VCE’s low-income customers.
• Target of 80-90 days cash reserve by the end of 2022
• Increased financial stability while taking a significant step toward establishing an investment-grade credit rating
• Preparing for future PCIA and power market volatility.

Other Considerations
• Power Costs - purchased power contingency of 2% / $1.3M • Customer programs costs related to launch of AgFIT and other programs. • Additional interest expenses related to the use of credit lines resulting from the delay of the ERRA proceeding.
• 5% annual salary and contractor inflation rate based on 2021 7% inflation rate • 5% administrative contingency rate (increased from 2.5%) for unanticipated expenses related to increase activity.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 75 Item 16 – VCE 2022 Budget
2022 Budget Scenario 1 (Low Income/At-Risk Credit) Staff Recommendation

VALLEY CLEAN ENERGY

DRAFT BUDGET SUMMARY
2022 - BUDGET SCENARIO 1 APPROVED ACTUAL YTD DRAFT
BUDGET Dec. 31 2022 BUDGET
FY 2021 (6 MO) FY 2021 (6 MO) CY 2022
OPERATING REVENUE $ 24,737 $ 29,677 $ 89,750
OPERATING EXPENSES:

Cost of Electricity 27,618 30,133 66,990
Contract Services 1,369 1,297 2,640
Outreach & Marketing 117 79 247
Programs 68 - 174
Staffing 580 537 1,300
General, Administration and other 382 349 840
TOTAL OPERATING EXPENSES 30,132 32,395 72,192
TOTAL OPERATING INCOME (5,395) (2,718) 17,558

NONOPERATING REVENUES (EXPENSES)
Interest income 28 9 17
Interest expense (23) (23) (107)
TOTAL NONOPERATING REV/(EXPENSES) 5 (14) (90)
NET MARGIN $ (5,390) $ (2,732) $ 17,468
NET MARGIN % -21.8% -9.2% 19.5%
• Budget Scenario 1
incorporates 2.5% rate credit
for CARE/FERA and Medical
Baseline
• Total customer rate credit:
$750k
• Directs all other revenues to
reserves.
• Includes a target of ~85 days
cash reserves by the end of
2022
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 76 Item 16 – VCE 2022 Budget
2022 Budget Scenario 2 (Base Case)

VALLEY CLEAN ENERGY

DRAFT BUDGET SUMMARY
2022 - BUDGET SCENARIO 2 APPROVED ACTUAL YTD DRAFT
BUDGET Dec. 31 2022 BUDGET
FY 2021 (6 MO) FY 2021 (6 MO) CY 2022
OPERATING REVENUE $ 24,737 $ 29,136 $ 90,500
OPERATING EXPENSES:

Cost of Electricity 27,618 29,746 66,990
Contract Services 1,369 1,300 2,640
Outreach & Marketing 117 85 247
Programs 68 23 174
Staffing 580 601 1,300
General, Administration and other 382 336 840
TOTAL OPERATING EXPENSES 30,132 32,090 72,192
TOTAL OPERATING INCOME (5,395) (2,954) 18,308

NONOPERATING REVENUES (EXPENSES)
Interest income 28 16 17
Interest expense (23) (23) (107)
TOTAL NONOPERATING REV/(EXPENSES) 5 (7) (90)
NET MARGIN $ (5,390) $ (2,961) $ 18,218
NET MARGIN % -21.8% -10.2% 20.1%
• All revenues are directed to
reserves
• No customer rate credit
modifications
• Includes a target of ~90 days
cash reserves by the end of
2022
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 77 Item 16 – VCE 2022 Budget
2022 Budget Scenario 3 (Low Income/At-Risk + Credit)
• 3.5% rate credit for
CARE/FERA and Medical
Baseline customers
• 1% rate credit for other
customers.
• Total customer rate credit:
$1.5M
• Includes a target of ~80 days
cash reserves by the end of
2022.

VALLEY CLEAN ENERGY

DRAFT BUDGET SUMMARY
2022 - BUDGET SCENARIO 3 APPROVED ACTUAL YTD DRAFT
BUDGET Dec. 31 2022 BUDGET
FY 2021 (6 MO) FY 2021 (6 MO) CY 2022
OPERATING REVENUE $ 24,737 $ 29,136 $ 89,000
OPERATING EXPENSES:

NONOPERATING REVENUES (EXPENSES)
Interest income 28 16 17
Interest expense (23) (23) (107)
TOTAL NONOPERATING REV/(EXPENSES) 5 (7) (90)
NET MARGIN $ (5,390) $ (2,961) $ 16,718
NET MARGIN % -21.8% -10.2% 18.8%
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 78 Item 16 – VCE 2022 Budget
Updated Budget Scenarios - Staff’s recommendation – Scenario 1 Scenario 1 FY2019 FY2020 FY2021 FY2022 CY2022 CY2023 CY2024 CY2025 Revenue 51,035 55,249 54,657 29,677 89,750 69,500 70,750 71,050 Power Cost 38,540 41,538 54,234 30,133 66,990 52,400 47,100 48,400 Other Expenses 3,850 4,346 4,267 2,276 5,292 5,398 5,506 5,616 Net Income 8,646 9,365 (3,844) (2,732) 17,468 11,702 18,144 17,034 Scenario 2 FY2019 FY2020 FY2021 FY2022 CY2022 CY2023 CY2024 CY2025 Revenue 51,035 55,249 54,657 29,677 90,500 70,250 71,500 71,800 Power Cost 38,540 41,538 54,234 30,133 66,990 52,400 47,100 48,400 Other Expenses 3,850 4,346 4,267 2,276 5,292 5,398 5,506 5,616 Net Income 8,646 9,365 (3,844) (2,732) 18,218 12,452 18,894 17,784 Scenario 3 FY2019 FY2020 FY2021 FY2022 CY2022 CY2023 CY2024 CY2025 Revenue 51,035 55,249 54,657 29,677 89,000 68,750 70,000 70,300 Power Cost 38,540 41,538 54,234 30,133 66,990 52,400 47,100 48,400 Other Expenses 3,850 4,346 4,267 2,276 5,292 5,398 5,506 5,616 Net Income 8,646 9,365 (3,844) (2,732) 16,718 10,952 17,394 16,284 Actual YTD
(6 Month)
Budget
Actuals Scenarios Preliminary Forecast*
Note: 2023, 2024, and 2025 forecasted financials are based on the most current available data and assumptions. These scenarios rely on future rate adjustments, reserves, or both to mitigate future power cost volatility.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 79 Item 16 – VCE 2022 Budget
Recommendation
Consistent with the adopted rate policy, Staff is recommending that VCE set rates for 2022 at a level that will fully fund the 2022 budget, build back reserves that have been used over the past 18 months to stabilize customer rates, and provide a level of financial relief to VCE’s low-income and at-risk customers.

Approve VCE 2022 Budget Scenario 1:
2022 Operating Budget Scenario 1 with $89.8M of operating revenues and $72.3M of operating expenses for a net income of $17.5M.

Discussion
Valley Clean Energy Board Meeting – February 10, 2022
via video/teleconference
Item 17 – Line of credit – Yolo County
80 yvonnehunterphotography.com
Public Comments
81 To Provide Public Comment on any agenda item please:
➢ E-mail 300 words or less to: [email protected] OR
Join the Public Comment Queue by
➢ “Raising Hand” on Zoom Meeting
OR
➢ Press *9 if joining by phone
Emailed comments received before the item has concluded will be read into the record.

Emailed comments received after the item has concluded but before the end of the meeting will not be read but will be included in the meeting record.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 82 Item 17 – Line of Credit (VCE / Yolo County)
Overview
• Background
• Line of Credit Summary
• Recommendation
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 83 Item 17 – Line of Credit (VCE / Yolo County)
Background
• Customer Rate Stabilization – 24 Months experienced COVID-19 pandemic, 2021 PCIA, power market prices, heat storm, drought, modeling, and CPUC delays. • Reserves Policy – 30 Day Min (2022 Reserve target of 80-90 days by December 31) • Current Financial Instrument – Line of Credit with River City for 5M Cash with $2M letter of credit capacity.
• 2022 PCIA and PG&E rates shows VCE net income ~$17M by the end of 2022.

Line of Credit Summary (Short Term – 12 Mo)
• Type of Financing: Line of Credit (maximum of 1 draw per month) • Maximum Amount: $5,000,000
• Maturity: December 31, 2022
• Collateral/Pledged Assets: VCE electric utility customer rates • Security: Rate covenant
• Interest Rate: Variable rate, simple interest, based on Yolo County Treasury Pool Quarterly Earnings Rate plus

1.50% (1.99% as of 12/31/2021)
• Late Penalty: 5% and 10% annualized until paid in full • Principal Payment Structure: Due in full on December 31, 2022 • Interest Payment Structure: Due in full on December 31, 2022 Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 84 Item 17 – Line of Credit (VCE / Yolo County)
Recommendation
Staff believes that the short-term cash requirement and the reduced but continued uncertainty related to the PCIA fee, resource adequacy costs, and PG&E bundled rates for 2023 justify adding the line of credit with the County of Yolo.

This agreement allows VCE to manage minimum short-term operational reserves and build back longer-term reserves of approximately 80 to 90 days cash by the end of 2022.

Additionally, credit support from both the County and River City Bank will allow VCE to optimize borrowing costs and provide additional assurance of rate stabilization.

Discussion
Valley Clean Energy Board Meeting – February 10, 2022
via video/teleconference
Item 18 – Strategic Plan Report
85 yvonnehunterphotography.com
Public Comments
86 To Provide Public Comment on any agenda item please:
➢ E-mail 300 words or less to: [email protected] OR
Join the Public Comment Queue by
➢ “Raising Hand” on Zoom Meeting
OR
➢ Press *9 if joining by phone
Emailed comments received before the item has concluded will be read into the record.

Emailed comments received after the item has concluded but before the end of the meeting will not be read but will be included in the meeting record.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 87 Item 18 – Strategic Plan Report
Overview
Inform the general manager and CAC of the summarized progress on the VCE Three-Year Strategic Plan goals ratified at the November 12, 2020.

Quarterly Report to VCE Management
• Staff will report quarterly to the Interim General Manager on the status of goals, objectives and metrics for which they are responsible.
• Annual Report to Board and CAC Staff
• Staff will report annually to the Board and CAC on the status of goals, objectives and metrics, and will recommend any mitigations or amendments as may be necessary for Board approval.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 88 Item 18 – Strategic Plan Report
GOAL 1 - FINANCIAL STRENGTH
Maintain a strong financial foundation and manage costs to achieve long-term organizational health.

1.1 - Maintain consistently healthy cash reserves to fund VCE’s mission, vision, and goals

1.2 - Achieve an investment grade credit rating by end of 2024.

1.3 - Commit to fiscal efficiencies to build a program foundation from which to deliver customer and community value.

1.4 - Manage customer rates to optimize VCE’s financial health while maintaining rate competitiveness with PG&E.

Obj. 2021 - Key Accomplishments & Developments 2022 Planned Activities

1.1 1. Developed collections policy for review by CAC & Board

2. Renewed credit line with RCB through calendar 2021.

3. Received preliminary CAPP approval for funding ~$800K of COVID related receivables

1. Collections policy approval Q1
2022

2. Renew and increase credit line(s)

1.2 1. Budgeted for a financial advisor to support the process of establishment of first credit rating

1. Issue RFP for financial advisor Q1
2022

2. Recover cash reserves ~80+ Days

1.3 1. Review financial reserve,
dividend, and programs fund
policy

1.4 1. Adopted cost-based rate policy

2. Implemented rate change to maintain cash reserve minimums

1. Develop an additional analytics
model for cost study and long-term rates.

Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 89 Item 18 – Strategic Plan Report
GOAL 2 - PROCUREMENT & POWER SUPPLY
Manage power supply resources to consistently exceed California’s Renewable Portfolio Standard (RPS) while working toward a resource portfolio that is 100% carbon neutral by 2030.

2.1 - Continue to identify and pursue cost effective local renewable energy resources.

2.2 - Acquire sufficient bundled energy and renewable resources to achieve VCE’s greenhouse gas reduction targets.

2.3 - Deploy storage and other strategies to achieve renewable, carbon neutral, resource adequacy, and resiliency objectives.

2.4 - Identify and pursue cost effective, local distributed energy (e.g., behind the meter rooftop Solar + storage) resources to help meet reliability needs.

2.5 - Study and present options for achieving a 100% carbon neutral resource portfolio as well as 100% carbon free resource portfolio (carbon free hour by hour) by 2030.

2.6 - Optimize the hedging strategy to mitigate risk in accordance with the energy risk guidelines and procurement plan.

Obj. 2021 - Key Accomplishments & Developments 2022 - Planned Activities

2.2 1. Q1 2021, executed a 90MW PV +75MW BESS 20 yr. PPA with Resurgence. (COD – Q422)

2. Q4 2021, executed a 72MW PV + 36MW BESS 15 yr PPA with Willow Springs. (COD – Q423)
Note: Both PPAs bring VCE stable, low-cost power, resource adequacy, and RPS compliance.

2.3 1. Participation in RFPs with CC power (1) for (2-3) long-duration energy storage systems. (2) firm clean resources (e.g., geothermal, biomass, other new technologies.) Note: Both support CPUC mandate for additional resources – D.21-06-035

1. Finalize negotiations and bring them
forward for Board approval.

2. Evaluate firm proposals and contract
awards for Board approval.

2.5 1. Staff and Carbon neutrality task group – (1) Awarded RFP to Energeia to perform portfolio analysis for 100% carbon neutral and carbon-free hour-by-hour. (2) Provided input and reviewed results for final recommendations

1. Final report to be delivered in
February 2022 to Board to begin

2.6 1. N/A for 2021

1. Comprehensive review planned to
incorporate long-term PPAs (EROC
participation)
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 9 0
Item 18 – Strategic Plan Report
GOAL 3 - CUSTOMERS & COMMUNITY (3.1 - 3.4)
Prioritize VCE’s community benefits and increase customer satisfaction and retention.

3.1 - Develop engagement strategies to increase awareness of, and participation in, local control of VCE’s energy supply and programs with a particular focus on engaging disadvantaged and historically marginalized communities.

3.2 - Develop programs and initiatives to better support community goals, including supporting member agency achievement of energy-sector emissions reduction targets.

3.3 - Design and implement a strategy to more effectively engage local business and agricultural customers.

3.4 - Build awareness and trust of the VCE brand through direct engagement with customers, communities and organizations.

Obj. 2021 - Key Accomplishments & Developments 2022 - Planned Activities

3.1 1. Initiated a mini-campaign in partnership with Davis Food Co-op on UltraGreen opt-ups, including collateral for the campaign.

2. Rolled out an online platform for customers to easily opt up online without their PG&E account number

1. Launch, publicize, create awareness of programs
for the low-income/at-risk

2. Expand opt-up campaigns for Woodland and
Winters (w/Spanish)

3. Implement a program for opt-up sponsorship of
low-income customers

3.2 1. Followed up on cost analysis for all member jurisdictions to opt up to UltraGreen re-initiated conversations about opting up.

2. Engaged the Woodland Sustainability Committee on VCE efforts and building electrification.

3. Engaged with the County of Yolo on the Climate Action Commission.

1. Upgrade analysis of impacts for enrollment of
Member jurisdictions in support of targeted
community goals.

2. Engage Key decision-makers in emission
reduction programs.

3.3 1. AgFIT pilot (1) Approved by CPUC with launch in 2022 (2) outreach developed for key ag customers

2. Developed and Launched campaign for UltraGreen commercial customers to advertise efforts and engage additional key accounts.

1. Successful AgFIT Launch in May-22.

2. Include additional key commercial accounts to
the UltraGreen campaign.

3.4 1. Directly engaged with Mutual Housing (MH) management staff and conducted three customer centered public meetings (1 in Spanish). This resulted in much more awareness of VCE’s brand and activities.

2. Made significant improvements to the VCE website, including adding content on carbon-free vs. renewables, highlighting key UltraGreen customers on the homepage, updating FAQs, updating the financial resources pageand adding the VCE Power Contract map

1. Continue to engage and continue conversations
about partnering with MH on programs, e.g.,
multi-family EV

2. Engage with GRID Alternatives for multi-family,
EV charging, and workforce development
training.

3. Continue to seek out opportunities to make
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 9 1
Item 18 – Strategic Plan Report
GOAL 3 - CUSTOMERS & COMMUNITY (3.5 – 3.7)
Prioritize VCE’s community benefits and increase customer satisfaction and retention.

3.5 - Develop customer programs and initiatives that prioritize decarbonization, community resiliency and customer savings.

3.6 - Measure and increase customer satisfaction, using tools such as surveys and focus groups, while maintaining an overall participation rate of no less than 90%.

3.7 - Integrate and address the concerns and priorities of emerging and historically marginalized communities in the design and implementation of VCE's services and programs.

Obj. 2021 - Key Accomplishments & Developments 2022 - Planned Activities

3.5 1. Made significant progress on three programs in Q3-4 2021. Ag pilot approved by the CPUC; programs for both EV rebates and heat pump rebates/support are in progress.

2. Staff was invited to present on building decarbonization to the Woodland Sustainability Committee (WSC) in January 2022

1. Approve and launch heat
pump and EV rebate program;
program design for higher
incentives for low-income
customers.

2. Incentivize low-income
community with programs
(CARE/FERA, PIPP, and ELRP.)

3.6 1. Maintained customer participation rate of over 90%

2. Reviewed and modified Opt-out process for improvements such as live customer service representative engagement for better awareness and education prior to final customer decision.

1. Focused engagement and
outreach with communities
with low participation.

3.7 1. Participating in Arrearage Management Program (AMP) and Percentage Income Payment Plan (PiPP) with PG&E and other CCAs so that customers at high risk of disconnection can get support in paying arrearages and avoid disconnection.

1. Monitor AMP and PiPP
implementation with PG&E
and SMUD.

2. Continue posting in Spanish,
measure success in Mar. 2022
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Item 18 – Strategic Plan Report
GOAL 4 - DECARBONIZATION & GRID INNOVATION
Promote and deploy local decarbonization and grid innovation programs to improve grid stability, reliability, community energy resilience, and safety.

4.1 - Working with a variety of local, regional and state partners, develop a grid innovation roadmap for VCE’s service territory that supports community energy resilience and reliability.

4.2 - Develop a VCE decarbonization roadmap to guide near and long-term program decisions and offerings.

4.3 - Increase participation in VCE’s UltraGreen 100% renewable product.

4.4 - Identify external funding sources to support decarbonization and grid-related programs and initiatives.

Obj. 2021 - Key Accomplishments & Developments 2022 - Planned Activities

4.1 1. Worked w/ the CAC on a building electrification statement. The Board adopted a statement supporting and encouraging the electrification of new buildings.

1. Engage with the County of Yolo planning commission
on decarbonization efforts.

4.2 1. Completed draft Carbon Neutral by 2030 Report (CNx2030).

1. Present final CNx2030 Report to Board Q1; Q3 return
to Board with recom. based on CNx2030 Report.

2. Energy Resilience Task Group to contribute to
building local energy resilience for essential
community needs.

4.3 1. Followed up with member jurisdiction staff for UltraGreen Analysis & adoption

2. Initiated a mini-campaign in partnership with Davis Food Co-op on UltraGreen opt-ups, including collateral for the campaign.

3. Rolled out online platform for customers to easily opt up online without their PG&E account number

1. Continue to identify opt-up solutions for member
jurisdictions

2. Analyze VCE opt-up numbers in Q2 2022

4.4 1. Applied for County of Yolo American Rescue Plan funding for downtown Winters reliability upgrade.

2. Applied for funding to CPUC under the Reliability OIR to develop and deploy an agricultural autoDR pilotReceived $325M in funds for the 3year pilot

1. Continue to identify ARP and other funding sources
with member districts, state, and federal agencies.

2. Tier 2 advice letter to be filed Jan 5, 2022.

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GOAL 5 - REGULATORY & LEGISLATIVE AFFAIRS
Strongly advocate for public policies that support VCE’s Vision/Mission.

5.1 - Work with CalCCA and other partners to proactively engage State regulators, legislators, and other State authorities in developing policy that furthers VCE’s mission and facilitates our contributions to decarbonization, grid reliability, energy resiliency, affordability, local programs and social equity.

5.2 - Develop relationships with community stakeholder organizations that foster support for VCE‘s mission and vision.

5.3 - Optimize regulatory compliance activities.

Obj. 2021 - Key Accomplishments & Developments 2022 - Planned Activities

5.1 1. Actively engaged in CalCCA sponsored legislation on PCIA – SB 612 (Portantino)

2. Active support of AB 843 (Aguiar-Curry) – access for CCA’s to BioMat resources

3. CAC Leg/Reg Task Group – bi-weekly meeting

1. Ongoing engagement in support
legislation related to CCAs

5.2 1. Identify key stakeholder groups within VCE service territory – in process,

2. Attended Winters Chamber of Commerce on 4.12.21

3. Met with Cool Davis to explore formalizing a relationship to work on shared decarbonization and electrification goals.

1. Decision around a structure to
formalize relationships with
community orgs (e.g., MOU
Template)

5.3 1. Engaged with CalCCA PCIA forecasting team to make more informed forecasts of PCIA and PG&E rates.

1. Recruitment of Regulatory
Staffing
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GOAL 6 - ORGANIZATION, WORKPLACE & TECHNOLOGY (6.1 – 6.4) Analyze and implement optimal long-term organizational, management, and information technology structure at VCE.

6.1 - Develop a roadmap to evaluate and guide future steps toward formation of a local Publicly Owned Utility (POU).

6.2 - Evaluate and pursue opportunities for shared services with other CCAs for certain functions.

6.3 - Develop an evaluation framework to guide future expansion opportunities beyond the existing service territory.

6.4 - Identify optimal management, staffing and contracting structure of VCE in the near and long term; factors include balance of internal staff vs. consultant support services, transition of leadership positions to permanent internal employees.

Obj. 2021 - Key Accomplishments & Developments Planned Activities

6.1 1. Continuing to monitor POU formation activities in PG&E service territory.

1. Outreach to CMUA

2. Evaluate funding options for
transitioning to a POU.

6.2 1. Continued Board and staff level engagement with CC Power for joint CCA procurement

1. Continued Board and staff level
engagement with CC Power for
joint CCA procurement.

6.3 1. Ongoing investigation of other CCA expansion evaluation methods used in the process.

2. Participation with the City of Stockton regarding the City’s CCA feasibility study

1. Continued Board and staff level
support for expansion
opportunities.

6.4 1. Budgeted (1) half time regulatory Analyst and (1) Intern for Marketing and Support 1. Recruitment for Analyst & Intern for 2022.

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GOAL 6 - ORGANIZATION, WORKPLACE & TECHNOLOGY (6.5 – 6.8) Analyze and implement optimal long-term organizational, management, and information technology structure at VCE.

6.5 - Promote diversity, equity and inclusion in leadership, hiring, promotion, and contracting policies.

6.6 - Support health, wellness and a productive workplace.

6.7 - Create an innovation-focused culture that rewards proactive participation, problem solving, new ideas, and creative use of partnerships.

6.8 - Deploy a modernized IT infrastructure that enables knowledge management, analytics and collaboration through robust use of data and information resources.

Obj. 2021 - Key Accomplishments & Developments Planned Activities

6.5 1. Completed annual diversity report (GO 156) for CPUC

2. Actively recruited for new hire Analyst position on multiple platforms, including women in science and engineering associations.

1. Will complete annual diversity report
(GO 156) for CPUC

6.6 1. Continued remote work option to address on-going pandemic issues.

1. Will continue remote work option as
necessary to address on-going
pandemic issues.

6.8 1. Working with County of Yolo GIS team on VCE platform for Dashboard and GIS mapping

2. Adopted Datto as an organizational network drive

1. Implement Dashboard and GIS
Mapping Q222

Valley Clean Energy Board of DirectorsFebruary 10, 2022

Valley Clean Energy Board of Directors
February 10, 2022