Valley Clean Energy Board of Directors Meeting – June 9, 2022 via video/teleconference
Item 15 – NEM 3.0 Update 1
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Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] • NEM 3.0 decision stalled in January
• Significant public backlash, including from Governor Newsom and solar industry • Proposed Decision contained significant new charges for solar customers, though existing customers and low-income customers may not be subject to the same charges. • California Public Utilities Commission (CPUC) reopened the record on the proceeding May 9; is seeking public input:
• Administrative Law Judge (ALJ) of the CPUC asking specific questions about the glide path approach, non-bypassable charges (NBCs) and Distributed Energy Resources (DERs)
• “Glide path approach” would give customers a fixed export adder in addition to the avoided cost calculator rate - the adder would step down over time; low-income customers may get a higher adder
• Proposed NBC charge to imports as well as behind-the-meter consumption (from Sierra Club) • DERs– whether low-income customers could benefit from tariff changes similar to the Community Solar/Disadvantaged Community Green Tariff
3 Item 15 – NEM 3.0 Update
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] • Most notably, no questions or feedback about about the proposed new grid charge
• Could be as high as $50-100/month
• Major focus of public (and solar industry) backlash
• Opening comments are due by June 10, reply comments are due by June 24 • To make a comment, go to:
https://apps.cpuc.ca.gov/apex/f?p=401:56:0::NO:RP,57,RIR:P5_PROCEEDING_SELECT:R200 8020 and click on “Add Public Comment”
4 Item 15 – NEM 3.0 Update
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] • CCAs are not uniform in response, but many do not support the NEM 3.0 Proposed Decision
• CAC supports making VCE’s position public
• Option: send letter to CPUC on behalf of VCE
• We urge the CPUC to re-evaluate the expensive grid charges • They are a financial burden to customers considering solar, especially low-income customers
• Disincentivize customers from going solar, putting roadblocks in the way of the state’s climate goals
• Battery storage should be more highly incentivized
5 Item 15 – NEM 3.0 Update
Valley Clean Energy Board of Directors Meeting – June 9, 2022 via video/teleconference
Item 16 – Overview of VCE Forecasting 6
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Market Price
Benchmarks
(MPBs)
External Models
and Forecasts
Revenues &
Administrative
Costs
Item 16 – Overview: Load and Power Costs Forecasting
Department Costs, Labor,
Programs
Total Power Costs
Base Cost Models
Budget Adoption Comprehensive Financial Model
(Annual & Long-term)
Revenue Model
(Rates)
VCE Generation
Power Costs Model
VCE Load
Update
(Demand)
Power Costs
(Supply)
PCIA COSTS
(PG&E ERRA
PROCEEDING)
CalCCA Model MRW
Administrative
Costs
Intercontinent
al Exchange
(ICE)
ACES S&P Platts
8 Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 9 Item 16 – Forecasting: Retail Load by Customer Class
40%
12%
13%
11%
4%
19%
0%
Residential
Small Commercial
Medium Commercial
Large Commercial
Industrial
Agricultural
Lighting
Wholesale load = retail load + 6% distribution losses
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 10 Item 16 – Forecasting: VCE Territory Historical Temperature Data -
10 20
30 40
50 60
70 80
90 2000200120022003200420052006200720082009201020112012201320142015201620172018201920202021 Degrees Fahrenheit
Avg of max temp.
Avg of avg temp.
Temps are modestly changing but isolated temperature events are becoming more pronounced Avg of min temp.
Notes: 1) Currently the average temperature is increasing by 0.36 degrees Fahrenheit per decade 2) Increasing the avg daily temp 1 degree Fahrenheit (across the entire year) resulted in a little over 1% increase in load annually (increase in summer and decrease in winter) Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 11 Item 16 – Forecasting: Impact of EV Adoption and Electrification • 2.2% load increase from
electrification in 2022, 42.7% load
increase from electrification (EV &
Bldg) by 2035
• Load increase from EV adoption
grows more quickly than building
electrification
• In 2022, 26% of the electrification
load increase is from EV adoption,
23% is from water heating
electrification, 52% is from space
heating electrification
• By 2035, 63% of the electrification
load increase is from EV adoption,
12% is from water heating
electrification, 25% is from space
heating electrification
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 MWh
Base Retail Load EV Adoption Building Electrification
Monitoring the adoption of bldg. electrification as well as EV’s is critical Note: VCE’s current peak load is approximately 230 MWs
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 12 Item 16 – Forecasting: Total Power Costs and Revenues Power Cost Risks
Annual Load - Overall performance
of VCE’s load within an acceptable
accuracy of 5% annually.
• Energy Costs - Main driver of
power cost overages. Annual
budget process vs hedging.
• Resource Adequacy (RA) -
Increasing CPUC mandated
requirements & decommissioning
Risk Description
2021
Risk
2022
Risk
Load
Forecast
VCE’s Annual forecast informs energy, resource
adequacy (RA), renewable portfolio standard
position, and multiple regulatory filings.
Energy
Costs
The risk of extreme fluctuations associated with
commodity prices, including energy prices,
resource adequacy, and other energy portfolio
components, remains.
Resource
Adequacy
Risk of additional regulatory requirements
increasing complexity and cost of operations
Power Cost - Corrective Actions Taken
• Power purchase agreements (PPA) – 238 MW of Renewable, 80% Energy costs, RA • 2020-22 Power content policy adjustments – Temp reduced the risk of energy costs. • Financial Calendar (Fiscal to Calendar year-end)
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 13 Item 16 – Forecasting: Total Power Costs and Revenues Risk Description
2021
Risk
2022
Risk
Power
Cost
Forecast
VCE’s Power Cost Forecast accuracy is essential
to VCE's ability to adjust customer rates to
recover costs, maintain reserves, and allow for
timely rate changes.
Customer
Rates
Risk of rate design for cost of service (non-time of
use (TOU), PCIA, demand charges, varying
generation rates) has been reduced. VCE will
continue to develop rate option(s) support risk
reductions.
Customer
Retention
VCE's launch in 2018 and the addition of Winters,
have the most risk of customer opt outs. Risk of
higher than expected opt-out level could
increased with rising rates.
Revenues Risks
• Power Cost Forecast – Central pillar
to setting rates.
• Customer Rates
• Matching Rate Policy (PG&E
Based)
• Cost-based Rate Policy
• Customer Retention – as forecasted
approximately 90% of eligible
customers in service territory.
Revenues Corrective Actions Taken
• Power Cost Forecasts – VCE has worked with SMUD to upgrade power cost model components that incorporate load update and forward market costs. • Customer Rate options - VCE evaluating customer rate options, as described in CAC companion Item 8 on this agenda, to ensure customer retention as a priority.
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 14 Item 16 – Forecasting: Total Power Costs and Revenues VCE Budget Risks
• Power Charge Indifference Adjustment (PCIA) - Volatile PCIA (+46% for 2021 and -57% for 2022)
• Use of VCE Reserves to stabilize customer rates, policies, and customer retention. • Administrative Costs – Minimized during volatile PCIA and Rates adjustments.
Budgeting Corrective Actions Taken
• Power Cost Contingency – $1.5M for approximately 2% of power costs budgeted • PCIA Forecasting – CalCCA Modeling
• Collections Policy – VCE adopted a collections policy to maintain healthy receivables VCE Annual Budget
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 15 Item 16 – Forecasting: Total Power Costs and Revenues VCE
MRW Keys &
Fox
New
Gen
CalCCA
(Provides shared resource platform)
Including input and feedback from other CCAs
Market
Analyst
Reports
CPUC
(Energy Division)
PCIA
(Power Charge Indifference
Adjustment)
Power Costs
Revenues
(Generation Rate)
S&P
Moody’s
PLATS
PG&E
SMUD
& ACES
(POWER
COSTS
Item X – Short Title and Slide Description [Calibri (Body) 29 font (not bold)] 16 Item 16 – Forecasting: Summary
• An inaccurate forecast can result in short term financial impacts • Overshooting the forecast results in:
• Higher RA obligations
• Unnecessary procurement
• Undershooting the forecast results in:
• RPS compliance risk (across compliance period)
• Need for additional procurement
• VCE Budget forecasting has been within 9% of actual financial performance • Energy Market Volatility - Budget Impacts will decrease significantly with Power Purchase Agreements. (90% of Budgeting)
• Continuous Improvement - Working with Partners and developing tools as necessary (e.g. CalCCA)
• Identifying Risks & Corrective Actions
• Forecasting is imperfect
Valley Clean Energy Board of Directors Meeting – June 9, 2022 via video/teleconference
Item 17 – Updated Draft Customer Rate/Product Options 17 yvonnehunterphotography.com yvonnehunterphotography.com Public Comments
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Join the Public Comment Queue by
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Item XX – Updated Draft Customer Rate/Product Options
19 Overview
• Background
• Updated draft customer rate/product options
• Tentative Timeline & Next Steps
• Discussion
Item XX – Updated Draft Customer Rate/Product Options
20 Background - Policy Drivers
• 2017 - VCE Implementation Plan: Program rates must collect sufficient revenue from participating customers to fully fund VCE’s budget, including the need to establish sufficient operating reserve funds.
• 2020 – Strategic Plan: Maintain financial stability while continuing to offer customer choice, competitive pricing and establishment of local programs. • 2018 – 2021 - Strong upward pressure on rates due to regulatory (PCIA, RA) and market conditions (power market price increases in 2020-22). VCE systematically analyzed policy options and implemented strategies to stabilize customer rates, reduce cost, and manage reserves.
• e.g.: Discontinue rate discount; temporary scale back REC purchases; sign long-term renewable PPA’s
• Nov. 2021 – Board adopts cost-based rates and temporary rate increase; directs staff to bring back additional customer rate option in mid-2022.
Item XX – Updated Draft Customer Rate/Product Options
21 Background - Primary Rate Setting Considerations
• Power Charge Indifference Adjustment (PCIA). A net 46% increase in the PCIA from 2020/21
• Resource Adequacy (RA) mandates and pricing
• Power Prices. Average forward market power prices have increased by nearly 60% since April-2021.
Other key rate setting considerations:
• Western Community Energy Bankruptcy. Regulatory financial oversight pressure • Implementation of Programs. Ample revenues and reserves required • PG&E Rate Adjustments.
• Geopolitical Climate. The conflict in Ukraine
• Supply chain interruptions. COVID Pandemic and U.S. trade restrictions • VCE Cash Reserves – Rate Stabilization
Item XX – Updated Draft Customer Rate/Product Options
22 Background – Additional Customer Rate Option
• 2020 – During budget adoption, Board direction to investigate additional customer rate option.
• 2020-21 – Staff, in consultation with CAC, research and develop additional customer rate option for Board consideration.
• Nov 2021 – Board postpones consideration of additional customer rate option. Directs staff to bring back in mid-2022.
Item XX – Updated Draft Customer Rate/Product Options
23 Background (CCA Community)
CCA IOU Territory Customer
Accounts
Number of
Rate Options
% Difference to IOU
Gen Rate (default
product)
Renewable Content Target (default product)
Valley Clean Energy PG&E 63,509 2 0% (match) 42%
Clean Power SF PG&E 311,777 2 0% (match) 50%
East Bay Community Energy PG&E 546,707 2 -1% 40%
MCE Clean Energy PG&E 473,826 3 -6% 60%
Peninsula Clean Energy PG&E 287,987 2 -5% 50%
Pioneer Community Energy PG&E 87,704 2 -6% 33%
San Jose Clean Energy PG&E 350,000 3 8% 60%
Silicon Valley Clean Energy PG&E 225,973 2 -0.50% 50%
Sonoma Clean Power PG&E 243,436 2 -0.50% 49%
Clean Power Alliance SCE 1,000,000 3 -6% 50%
(Los Angeles area)
Desert Clean Energy SCE 37,375 2 14% 100%
Notes:
(1) The above information is based on recent publicly available data and is subject to change per IOU and/or CCA rate activities and PCIA adjustments. (2) VCE's current year target renewable content rate is 20% due to cost-cutting strategies. (3) Due to the PCIA structure, each CCA has a specific "vintage" date based on what year it launched service and how it phased in its customer base.
Item XX – Updated Draft Customer Rate/Product Options
24 Current Customer Rate/Product Options
• VCE currently offers two retail energy product categories:
1) "Standard Green" which is at least 75% carbon-free and 25% renewable 2) "UltraGreen" which is both 100% carbon-free and 100% renewable. • VCE Rate Policy: Match PG&E + Customer Dividend
• Discount for CARES and FERA
Updated Draft Customer Rate/Product Options
• Draft customer product structure with three options could be established by implementing a new "GreenSaver" option.
Proposed “GreenSaver” option:
1. Increased customer choice by adding a new least-cost customer option • Approximately 0.5% below PG&E (Total Bill)
2. 5% more renewable than California RPS requirements
Note: VCE's existing customer dividend program would continue to provide VCE with a mechanism to credit eligible customers when VCE reaches its financial/reserve objectives.
Item XX – Updated Draft Customer Rate/Product Options
25 “GreenSaver” (New “Least Cost”
product: Priced 0.5% below PG&E with
energy sources at least 5% above RPS target)
Standard Green
(Existing Default: cost-based rate)
UltraGreen 100% Renewable
(Existing Opt-Up: cost-based rate)
Draft Customer Rate Structure (Design)
Customer Rate Option Rate Portfolio Notes
GreenSaver (new)
Less than PG&E
(-0.5%) total bill
comparison
5% above RPS
requirements
• Ineligible to participate in customer dividend program; reduced access to full customer program benefits
• CARE/FERA customers maintain the existing VCE multi-year portfolio mix for Standard Green default through 2023
Standard Green - Default
(existing) Cost-based Maintain existing VCE
multi-year portfolio mix
• Portfolio minimum percent renewable content above
GreenSaver to maintain product differentiation
• Eligible for customer dividend program and full customer program benefits
UltraGreen –
Opt-up (existing) Cost-based Maintain existing 100%
renewable portfolio
• Eligible for customer dividend program and full customer program benefits
VCE Draft Customer Products (Content and Pricing Strategy) GreenSaver Standard Green UltraGreen PG&E
Approxmently 5% above
RPS Target
45% Renewable
75% Carbon-free
100% Renewable
100% Carbon-free **29% Renewable
Average Total Costs
$171.15
Average Total Costs
$172.46
Average Total Costs
$180.97
Average Total Costs
$172.46
Electric Generation
$64.15
Electric Generation
$65.46
Electric Generation
$73.97
Electric Generation
$79.46
PG&E Added Fees
$14.00
PG&E Added Fees
$14.00
PG&E Added Fees
$14.00
PG&E Added Fees
(Included in Generation)
PF&E Delivery Charges
$93.00
PF&E Delivery Charges
$93.00
PF&E Delivery Charges
$93.00
PF&E Delivery Charges
$93.00
Average lower by
0.5% of Total Bill
(1-2% Gen Discount)
Average $7-10 Per Month
*Sample Residential Cost Comparion
Item XX – Updated Draft Customer Rate/Product Options
26 Draft Customer Rate/Product Analysis
• Based on staff research, CCA programs with additional customer product options and cost-recovery rates have not experienced significant "opt-out" or "opt down" activity. (residential and commercial/industrial) • VCE would continue as planned to grow its overall environmentally beneficial portfolio New
“GreenSaver”
customer
option 5%
above RPS
target &
lower on a
total bill
comparison to
PG&E by
0.5%.
“Standard
Green” is the
current
default
“basis” rate
with
increased
renewable
energy priced
to recover
costs + build
reserves.
*Typical Monthly Electric Charges based on typical usage of a residential customer in VCE service area (547 KWH/Month) of PG&E rates and VCE rates effective as of March 1, 2022 under the E-1 rate schedule. Actual differences may vary depending on usage, rate schedule and other factors. Estimate provided is a monthly 12-month period. **Note: Represents the mot resent (2019) power content data reported to the California Energy Commission's Power Source Disclosure Program Item XX – Updated Draft Customer Rate/Product Options
27 Draft Customer Rate/Product – CAC Initial Feedback
• Product Differentiation – Standard Green –> "GreenSaver" • Analysis of how long to provide this option as VCE moves toward a 100% renewable future.
• Marketing framework for introducing the new product
• Organizational Cost/Benefit – Value of additional customer choice vs. the effort/value added and risk of customer "opt down."
-
50 100
150
200
250
300
350
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
2021 2022 2023 2024 2025
Forecasted Cummulative Net Margin & Days Cash
VCECummulative Margin VCE Days Cash
Item XX – Updated Draft Customer Rate/Product Options
28 Example Reserves Timeline
Cumulative
Net Margin
(1,000’s)
Days
Cash
Targeted Reserves of
180+ Days
Item XX – Updated Draft Customer Rate/Product Options
29 Draft Customer Rate/Product - Tentative Timeline
• May 2022: CAC Introduction/feedback on updated draft rate options. Completed. • June 2022: Board Introduction/feedback on updated draft rate options. Current. • June 2022: CAC consideration/recommendation on updated draft rate options. • July 2022: Board consideration of final updated draft rate options.
Initial Findings
• Adding a least-cost GreenSaver customer rate/product option enhances local control, customer choice, and cost competitiveness
• Adding GreenSaver does not alter VCE's overall portfolio or progress toward 2030 renewable goals.
• Set rates to meet costs/build reserves with lower customer opt-out risk • Enhances VCE's ability to execute local programs.
• Enhances ability to attract new member jurisdictions.