Central Coast Community Energy (3CE) Policy Board
March 19, 2025

Policy Board of Directors
March 19, 2025
1:30pm
Central Coast Community Energy
70 Garden Court, Suite 300
Monterey, CA 93940

REMOTE LOCATION VIA TELECONFERENCE
Any interested parties or community members may attend, and participate in, the meeting at the following addresses where Board members may also join the meeting from:

County of Santa Cruz
701 Ocean Street, 701 Community Room
Santa Cruz, CA 95060
City of Greenfield
108 El Camino Real
Greenfield, CA 93927
County of San Luis Obispo
Katcho Achadjian Government Center
1055 Monterey Street,
Board of Supervisors Chambers
San Luis Obispo, CA 93408
City of Santa Maria
City Hall
110 East Cook Street, Council Chambers
Santa Maria, CA 93454
County of Santa Barbara
County Administration Building
105 East Anapamu Street,
Fourth Floor
Santa Barbara, CA 93101
Public may participate through ZOOM. For ZOOM participation please join by computer audio at:
https://us02web.zoom.us/j/83507087702
Or join by phone:
+1 669 900 6833 or +1 669 219 2599
Enter this Webinar ID Number: 835 0708 7702 when prompted. Please note there is no Participant Code, you will press # again after the recording prompts you.

You will be placed in the meeting as an attendee. To make a public comment:
 If joined by computer, please press the button to raise your hand  If joined by phone, please push *9 on your keypad
If you have anything that you wish to be distributed to the Board, please provide 15 copies to a member of 3CE staff or the Board Clerk, who will distribute the information to the Board members and staff.

The public may comment on the consent agenda and matters not listed on the agenda but within the Board's jurisdiction at the opening of the meeting. The Board may not take action at this meeting on any item not listed on the Agenda other than to refer the matter to staff or set it for a future meeting. The public may comment on a specific item listed on this agenda when the Board considers that item.

Speakers are limited to 3 minutes each.

In addition, members of the public may request and receive copies without undue delay of any documents that are distributed to the Board, unless there is a specific exemption under the Public Records Act that prevents the disclosure of the record. (Cal. Gov’t Code Section 54957.5) In compliance with Government Code Section 54957.5, non-exempt writings that are distributed to a majority or all of the Board in advance of a meeting and that relate to an agenda item will be made available at 3CE’s offices located at 70 Garden Court, Suite 300, Monterey, CA 93940 during normal business hours and are also available on the 3CE website located at: https://pub-3ce.escribemeetings.com/ REASONABLE ACCOMMODATIONS: In compliance with the Americans with Disabilities Act, any individuals who desire to request a reasonable accommodation or modification to observe or participate in the meeting may make such a request by sending an email to: [email protected] Copies of documents may be made in alternative formats, upon request. Requests for accommodations should be made no later than two (2) business days prior to the meeting to allow time for 3CE to address the request.

DISCLOSURE OF CAMPAIGN CONTRIBUTIONS: Pursuant to Government Code section 84308, members of the Board are disqualified and not able to participate in any agenda item involving contracts (other than competitively bid, labor, or personal employment contracts), franchises, discretionary land use permits and other entitlements if the Board member received more than $250 in campaign contributions from the applicant or contractor, an agent of the applicant or contractor, or any financially interested participant who actively supports or opposes the decision on the agenda item since January 1, 2023. Members of the Board who have received, and applicants, contractors or their agents who have made, campaign contributions totaling more than $250 to a Board member during the proceeding or for 12 months after a final decision is rendered in that proceeding, are required to disclose that fact for the official record of the subject proceeding. Disclosures must include the amount of the campaign contribution and identify the recipient Board member and may be made either in writing to the Clerk of the Board prior to the subject hearing or by verbal disclosure at the time of the hearing.

Welcome & Roll Call
Pledge of Allegiance
Corrections or Additions
The Clerk will announce agenda corrections or proposed additions of emergency, urgency, or continued items, which will be acted on by the Board as provided in Section 54954.2 of the California Government Code.

Public Comment on Items on the Consent Calendar and Items Not listed on the Agenda The public may address the Board on the Consent Calendar and any matter within the jurisdiction of the Board but not on the agenda.

PRESENTATION

1. Receive a presentation on the 2024 Annual Impact Report

CONSENT CALENDAR

2. Approve minutes from the December 11, 2024, meeting of the Policy Board of Directors

3. Update on 3CE's Energy Programs

4. Regulatory and Legislative Quarterly Update

5. Financial report for the period October 1, 2024, through December 31, 2024

6. Investment Performance Report for the period of October 1, 2023 through September 30, 2024

7. Investment Performance Report for the period of October 1, 2024 through December 31, 2024

8. Adopt Resolution No. PB-2025-01 establishing a Claims Procedure Pursuant to Government Code Section 935

REGULAR AGENDA

9. CEO Report
a. Staffing Updates
b. Community Advisory Council Report
c. EV Charger Asset Pilot Update
d. Power Supply Update
e. California Public Utilities Commission Action on General Order 167

10. Receive a presentation on the Power Charge Indifference Adjustment and provide staff direction

11. Receive a presentation on 3CE's FY 2023-24 audited financial statements

12. Adopt Resolution No. PB-2025-02 approving adjustments to the calendar year 2025 electric generation rates effective April 1, 2025

13. Closed session under Government Code 54950 et. seq. relating to the following item:
a. Pursuant to Government Code section 54957(b), the Board will confer regarding evaluation of performance for the Chief Executive Officer
Board reports or comments
Adjournment
Staff Report Item 1
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Dawn Mathes-Park, Director of Communications and Outreach SUBJECT: Receive a presentation on the 2024 Annual Impact Report DATE: March 19, 2025
RECOMMENDATION:

This report recommends the Policy Board receive a presentation on the 2024 Annual Impact Report.

BACKGROUND:
3CE’s 2024 Annual Impact Report highlights the agency’s key accomplishments in fulfilling its mission to supply reliable, affordable, clean electricity; reduce greenhouse gas emissions, and strengthen our local economies. The publication is an opportunity to showcase the innovative power procurement, energy programs, and community engagement efforts made possible by 3CE customers.

DISCUSSION:

In FY 2023-24, 3CE made nearly $15 million available for electrification rebates and incentives through its Energy Programs and distributed nearly $4 million to projects for income qualified customers and underserved communities. Since 2018, nearly 10,000 customers have participated in 3CE’s programs.

The agency’s recent investments in innovative geothermal, wind, storage, and solar renewable energy projects are featured in the 2024 Annual Impact Report. Highlights include:
- Casa Diablo is California’s newest and most innovative geothermal energy project, providing clean and reliable energy 24 hours a day.
- Willow Rock Energy Storage Center is unlike other battery storage projects; instead of lithium, it will use compressed air to generate power on demand.
- Atlas Solar will provide 150 megawatts for 3CE customers, enough to power 105,000 homes. - Aratina Solar + Storage will supply 120 megawatts for 3CE customers, enough to power 90,000 homes.
- Victory Pass Solar + Storage provides 100 megawatts for 3CE customers, enough to power 68,000 homes.

In addition to sourcing renewable energy, meeting our clean energy goals depends upon active customer outreach, education, and engagement. To that end, in 2024, 3CE participated in nearly 160

local community events, maintained memberships with 41 organizations, and hosted four webinars in English and three webinars in Spanish. This year, 3CE also hosted industry-specific forums tailored to the needs of commercial and agricultural customers, as well as those customers enrolled in the Net Energy Metering program.

Altogether, the report demonstrates consistent progress toward agency goals and significant community benefits and impact.

FISCAL IMPACT:

There is no fiscal impact to this report.

ATTACHMENT(S):

1. 2024 Annual Impact Report

2023-24 COMMUNITY INVESTMENT*

NEW CONSTRUCTION ELECTRIFICATION

PROGRAM REBATES BUILT MORE THAN
200 NEW, ALL-ELECTRIC AFFORDABLE
HOUSING UNITS IN 2024

FINANCIAL RESOURCES FOR HOMES

AND BUSINESSES

RESIDENTIAL BATTERY REBATE

PROGRAM EMPOWERS CUSTOMERS

REBATES HAVE FUNDED ELECTRIFICATION
FOR OUR CENTRAL COAST SINCE 2018
3CE CUSTOMERS ARE DOING MORE

WITH THEIR ENERGY
3CE is helping our communities and our customers save money while transitioning transportation, households, and businesses from fossil fuels to clean, all-electric power
Plug into technical assistance and rebates for baeries, EVs & chargers, all-electric agriculture equipment and appliances Nearly $15 million available in rebates and incentives for households, businesses, and public agencies
$11 million in total rebates distributed
$4 million in rebates distributed to equi projects
Since 2018, more than 7,000 customers received rebates
“When it was time to
replace one of our fleet
vehicles, we knew we
wanted to explore electric
options. 3CE’s rebates
made the decision even
easier. Their program was
straightforward and
provided a significant
incentive that helped us
make the switch to
electric. We’ve seen a
noticeable decrease in
our fuel costs without any
compromise in our
service to our customers.

Thanks to 3CE, the
all-electric truck
purchase was a true
win-win for the Aromas
Water District and the
communi we serve.”
— Robert Johnson,
General Manager,
Aromas Water District
Rebate covers equipment and installation, allowing
participants to charge baeries during the day when
renewables are available and electrici prices are
lowest, and discharge baeries end-of-day during
peak times when prices are highest
2,843 Electric Vehicles
2,085 EV Chargers
1,633 Projects for EV Readiness
38 Electric Buses
746 All-Electric Water Heaters & HVAC Systems
1,458 All-Electric Aordable Housing Units
93 Agricultural Equipment Electrification Projects
3CE GIVES YOU THE POWER TO

DO MORE WITH YOUR ENERGY
• Plug into rebates for EVs & chargers, all-electric agricultural equipment and household baeries and appliances
• Reduce local emissions for healthier air
• Take control of your energy usage
• Support your local economy
• Give your communi a voice in the statewide energy
conversation
• Make California’s grid cleaner and more reliable
ANNUAL
REPORT
2024
“The rebates we
received through this
program will allow us to
transport kids to
where they need to be,
even from rural areas.

We couldn’t have done
this without the help of
3CE funds.”
— Kris Sihler,
Transportation
Manager, Santa Cruz
Ci Schools
Central Coast Community Energy
70 Garden Court, Suite 300
Monterey, CA 93940

PRESORT STD
U.S. POSTAGE
PAID

CENTRAL COAST COM-MUNITY ENERGY

POWER FOR GOOD
Learn More
www.3CEnergy.org/about-us *3CE’s Fiscal Year runs Oct. 1 – Sept. 30 Page 5 of 146 Regional oces in Monterey and San Luis Obispo; Santa Cruz oce opening in 2025
160 communi events aended, supported, and/or hosted
41 memberships with local communi-based organizations
16 farmworker outreach events
7 webinars in English and Spanish
2 communi workshops
3CE NOW SERVES
5 COUNTIES
30 CITIES
94%+

CUSTOMERS

ENROLLED

1.2M+

CUSTOMERS
Simply by being a 3CE customer, you
empower 3CE to invest in local
communities and build a cleaner, more
reliable grid for all Californians. And by taking
advantage of our rebates to electri your
transportation, home, or business, you can
speed the transition to a clean-energy future.

Every 3CE customer is making a dierence.

The impacts of locally controlled clean energy are
profound. Together, we are reducing regional emissions
for cleaner, healthier air and improving the economic
health of households, businesses, and entire communities.

As a 3CE customer, you make a valuable contribution to
powerful progress.
3CE’s Prepay Program for Power
Purchase Agreements has delivered
significant benefits. By prepaying for
electrici through a $648 million bond
issuance in 2023, 3CE is projected to
reduce energy costs by nearly 11.4%
over the initial seven-year period of the
bonds, saving customers $32.9 million.

WORKING TOGETHER,

AND USING POWER FOR GOOD
2024

CLEAN ENERGY HIGHLIGHTS

BUILDING CAPACITY ADDING NEW RENEWABLE

ENERGY SOURCES TO THE GRID

POWERFUL PROGRESS
TOWARD 100% RENEWABLE ENERGY

GENERATING RESULTS

DELIVERING NEW RENEWABLE ENERGY

MEETING COMMUNITY MEMBERS

WHERE THEY ARE
Covering Ground
Innovative Renewable Energy Generation
Casa Diablo Geothermal, Mono Coun, CA
One of 21 new renewable energy projects 3CE has
supported, the Casa Diablo Geothermal Plant is
California’s newest and most innovative geothermal
energy generation site. Geothermal energy is clean and
reliable 24 hours a day, and 3CE and its customers
played an integral role in bringing this landmark project to fruition.

Spreading the Word
Spanish-language services and material
Underserved Communities Action Plan to reach underserved communities
Forums tailored for solar, commercial, and agricultural customers Workshops for contractors, builders, aordable housing
developers, and communi advocates
Addressing the unique needs of our diverse Central Coast Giving You Greater Control Over Your Electrici Needs
Providing a choice for service to all electrici customers Residential Baery Rebate Program
OhmConnect partnership
Hourly Flex Pricing Pilot
3CE Lowers Energy Costs via
Power Prepayment
Atlas Solar
1 gigawa solar energy generation
150 megawas for 3CE customers*
*Enough to power 105,100 homes
of clean & renewable energy
in 2024, enough to power
350,850 households
Sourcing Renewable Energy
Sourced 409 Megawas
avoided more than
445,000 metric tons of
CO2 in 2023, the equivalent
of taking 105,911
gasoline-powered
passenger vehicles o the
road for a year.

Aratina Solar + Storage
530 megawas solar energy generation
600 megawas baery storage capaci
120 megawas for 3CE customers*
*Enough to power 90,000 homes
Victory Pass Solar + Storage
200 megawas solar energy generation
50 megawas baery storage capaci
100 megawas for 3CE customers*
*Enough to power 68,000 homes
The Future of Energy Storage
Willow Rock Energy Storage Center, Kern Coun, CA
Baery storage capaci is essential for California’s
transition to carbon-free energy. Willow Rock Energy
Storage isn’t your pical baery; instead of lithium, it
uses compressed air to generate power on demand. By
supporting projects like this, 3CE customers are
contributing to revolutionary innovation.
46 MW
Baery Storage
20% LOAD
234 MW
Geothermal
Solar
Wind
24% LOAD
309 MW
Geothermal
Solar
Wind
29% LOAD
409 MW
Geothermal
Solar
Wind
49% LOAD
757 MW
Geothermal
Solar
Wind
56% LOAD
849 MW
Geothermal
Solar
Wind
85 MW
Baery Storage
110 MW
Baery Storage
381 MW
Baery Storage
584 MW
Baery Storage
2022 2023 2024-25 2026 2027
Atlas
Under Development
La Paz County, AZ
Solar
Yellow Pine Online
Clark County, NV
Solar+Storage
OME Fish Lake
Under Development
Esmeralda County, NV
Geothermal
Under Development
Lincoln, Torrance &
San Miguel Counties, NM SunZia Wind Project
Wind
Casa Diablo-IV
Casa Diablo Mono County, CA
Geothermal
Online
COSO Geothermal
Inyo County, CA
Geothermal
Online
Aratina
Kern County, CA
Solar+Storage
Under Development
Jasmine
Kern County, CA
Solar+Storage
Under Development
Rabbitbrush
Kern County, CA
Solar + Storage
Online
Slate
Kings County, CA
Solar+Storage
Online
Panoche Hybrid
Midway Hybrid
Fresno County, CA
Storage
Under Development
San Luis West
Fresno County, CA
Solar+Storage
Under Developlemt
RPCA Storage 1
Santa Barbara County, CA
Storage
Under Development
Mountain View Wind
Repowering Project
Riverside County, CA
Wind
Online
California Flats
Monterey County, CA
Storage
Online
Willow Rock Energy
Storage Center
Kern County, CA
Storage
Under Development
Angela
Tulare County, CA
Solar+Storage
Under Development
Long Duration Energy Storage
Bodega Energy Storage
Green Valley Energy Storage
Rava Mesa Energy Stroage
Monterey County, CA
Storage
Under Development
San Gabriel Energy Storage
Los Angeles County, CA
Storage
Under Development
Victory Pass
Riverside County, CA
Solar+Storage
Online

Staff Report Item 3
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Inaara Muhammad, Manager of Energy Programs SUBJECT: Update on 3CE’s Energy Programs
DATE: March 19, 2025
RECOMMENDATION:

Receive an update on 3CE’s Energy Programs.

BACKGROUND:
3CE’s Energy Programs have been administered since 2019 to support 3CE’s mission by serving the Central Coast community with incentives to engage in electrification initiatives, strengthen the local economy, and reduce greenhouse gas emissions. The Energy Programs portfolio has undergone several iterations to improve community-wide accessibility and achieve parity for priority communities.

Currently, 3CE offers 11 programs and two pilots to support residential, commercial, and public agency electrification efforts in the transportation, building, and agricultural sectors.

DISCUSSION/ANALYSIS:

As part of 3CE’s commitment to customers, 3CE staff continually evaluate Energy Programs’ performance by tracking several key indicators and use this analysis to improve the impact of 3CE’s Energy Programs.

The first quarter of FY 2024-25 began with steady participation in 3CE's Energy Programs. This is in part due to the new Customer Relationship Management (CRM) system, which allowed for no disruption to the agency’s energy programs offerings during the transition to a new fiscal year. The Energy Programs Update for Q1 FY2024-25 (Attachment 1) shows highlights of the agency’s programs’ impact in the first quarter.

3CE’s Energy Programs Portfolio Analysis Update (Attachment 2) gives a more detailed status update of the individual Energy Programs for FY 2024-25 with data collected through January 2025. These status updates share a variety of program performance metrics including equipment incentivized, housing units electrified, dollars spent, and performance on equity (e.g., incentives and support for income-qualified customers.) The update also describes strategic initiatives currently underway to enhance the Energy Programs portfolio through pilots and new program offerings. Below are highlights of several strategic initiatives across Energy Programs’ focus areas.  Transportation Electrification
- On December 11, 2024, the Policy Board approved an EV Charger Asset Pilot at 3CE’s offices located at 1026 Palm Street in San Luis Obispo. The project, which has completed design and is being actively constructed, includes five parking spaces serviced by three Level 2 charging stations and will enable 3CE to evaluate workplace charging efficacy and load management synergies, such as vehicle-to-load charging. 3CE recently received a $68,000.00 USD grant from the SLO APCD, which will alleviate approximately 60% of the equipment purchases and installation costs.
 Building Electrification
- In November 2024, 3CE hosted two community listening sessions to gather feedback on 3CE’s current Electrify Your Home program and potential improvements to the program’s design. On February 5th, 3CE staff presented the findings from the listening sessions to the Community Advisory Council (CAC), along with a preliminary improved program concept that included contractor education, home assessments, a direct install pilot, and additional rebates. The program will continue to be developed with feedback from a second round of listening sessions, which will be held on April 3rd at The Goleta Valley Community Center, and April 10th at The Watsonville Civic Plaza Community Room.
 Ag Electrification
- 3CE staff are beginning to evaluate the potential for enhancements to the current Ag Electrification program, including whether the program could benefit from a similar community workshop approach as is currently being conducted with the CAC for Electrify Your Home.
 Demand Response
- 3CE staff is launching the Hourly Flex Pricing Expanded Pilots 1 and 2 in Q1 2025. The pilot project is designed to enable significant customer savings and grid operational benefits through real-time, dynamic price signals and automated control of equipment for eligible agricultural, residential, and commercial customers. - The Residential Battery Rebate Program introduced a new scheduling assistance service to help customers set their battery systems to discharge during peak hours. In its first

week, eight customers signed up to receive assistance. Staff are conducting direct outreach to rebate applicants to offer assistance and ensure they meet the Program’s discharge requirements.

FISCAL IMPACT:

There is no fiscal impact associated with this report and update.

CONCLUSION:
3CE’s Energy Programs support California’s Central Coast communities by providing funding and services to accelerate regional electrification, reduce greenhouse gas emissions, and benefit local customers and economies.

ATTACHMENT(S):

1. Energy Programs Update for Q1 FY 2024-25

2. 3CE Energy Programs Portfolio Analysis Update

Energy Programs Updates
FY 2024-25 Q1
We serve our central coast community by providing reliable, affordable, clean electricity and electrification programs to reduce greenhouse gas emissions and strengthen our local economy.

Over 142 MT CO2e avoided as of 1Q25
82 gas cars off the road 4
with support of
Electrify Your Ride
ag equipment transitioned
to electric alternatives with
support of Agricultural
Electrification Program
*calculated using EPA and CARB reference data
• City of Salinas
• City of San Luis Obispo
• City of Soledad
• County of Santa Barbara
Plan Your Fleet
County of Santa Barbara .................. 60 L2s
Charge & Electrify Your Fleet
Bee Farm in Santa Barbara
$64,829
Ag Electrification Program
ADU in San Luis Obispo
$165,000
New Construction Elec. Program
13 kW battery in Monterey
$6,500
Residential Battery Rebate Program
Reach Codes
City of Goleta - New Construction (underway)
City of San Luis Obispo - Existing Buildings Update (underway) City of Santa Cruz - Existing Buildings (underway)
County of Monterey - EV Charging Infrastructure (underway)

3CE’s Energy Programs Portfolio Update
This report provides an update on participation in Central Coast Community Energy’s (3CE) Energy Programs Portfolio with data collected through January 2025.

TRANSPORTATION ELECTRIFICATION
Electrify Your Ride Program
3CE’s Electrify Your Ride (EYR) program incentivizes residential and commercial electrification through rebates for the purchase or lease of an electric vehicle (EV), for purchase of Level 2 and Direct Current Fast Chargers, and for electrical work necessary to install chargers. In addition, EYR provides technical assistance for EV infrastructure build-out at publicly accessible commercial sites and at multifamily residential properties. The FY 2024-25 budget for EYR is $4.1 million.

Incentives are available on a first-come, first-served basis until funding is fully awarded. To promote greater adoption of transportation electrification in disadvantaged and low-income communities, higher incentive amounts are available for income-qualified customers and multifamily-unit buildings.

In FY 2024-25, EYR has distributed over $1,215,371 in rebates across five counties, enabling over $16.1 million in EV and EV charger purchases. The EV purchases have resulted in over 1,102 MT CO2e avoided, which is equivalent to removing 257 gas cars off the road for one year.

Figure 1 (above): EYR funds distributed by county in FY 2024-25.

Figure 2 (above): EYR funds distributed by incentive type in FY 2024-25.

Figure 3 (above): EYR funds distributed to income-qualified applicants in FY 2024-25.

Tier 1 = 201 - 400% FPL; Tier 2 = < 200% FPL; Standard = Non-Income Qualified Applicants Electric Bus Program
3CE’s Electric Bus program provides public schools/school districts, farmworker transit organizations, and public transit agencies enrolled in 3CE service the opportunity to receive incentives to support the

purchase of up to five all-electric buses. In FY 2024-25, the budget for the Electric Bus program is $1.4 million.

Applications are accepted until funds are fully distributed. Applicants are encouraged to apply for rebates following the purchase and delivery of an electric bus. Notices of Qualification (NOQ) may be requested to assure applicants of their eligibility status. Program recipients may elect for funds to be distributed directly from 3CE to the bus manufacturer upon receipt of the final invoice. Applicants are encouraged to stack/leverage other incentive funds and no matching fund restrictions apply.

To date, 3CE has distributed $537,723 in rebates for four electric school buses in four counties. These rebates have helped enable over $1.6M in electric bus purchases. 3CE staff continue to actively engage with the community to promote the program to interested schools, organizations, and transit authorities.

County Applicant Type Total Funding
Total # of
E-Buses
% of Funding to Title
1 School or Low-Income Community
Monterey 1 School District $200,000 1 100%
San Benito 1 School District $75,167.98 1 0%
San Luis Obispo N/A - - -
Santa Barbara 1 School District $62,555.17 1 100%
Santa Cruz 1 School District $200,000 1 0%
Total: 4 School Districts $537,723.15 4 50%
Plan Your Fleet Program
3CE’s Plan Your Fleet (PYF) program provides planning, design, and engineering consulting to Member Agencies to accelerate fleet electrification and EV charging infrastructure development across the Central Coast. The FY 2024-25 budget for Plan Your Fleet is $650,000.

The following jurisdictions have engaged with the Plan Your Fleet program so far, this fiscal year:
 City of Atascadero
 City of Capitola
 City of Carmel-by-the-Sea
 City of Guadalupe
 City of Salinas
 City of San Luis Obispo
 City of Soledad
 County of Santa Barbara
Additional jurisdictions are planning to engage in the coming months and will be included in the report as each scope is finalized.

Charge Your Fleet Program
3CE’s Charge Your Fleet (CYF) program provides rebates for the purchase and installation of Level 2 or Level 3 (DC Fast Chargers) EV chargers. Member Agencies are eligible for up to $150,000 in funding support each fiscal year. 3CE’s 2024-25 CYF budget totals $1.0 million.

In FY 2024-25, the program has incentivized 60 chargers totaling $150,000.00 and is actively engaging with additional Member Agencies who are in the process of installing EV chargers, including the City of Monterey and City of Carmel-by-the-Sea. 3CE expects increased participation later in the fiscal year as Member Agencies who participated in FY 2023-24's Plan Your Fleet program implement their plans.

Member Agency Equipment Type Quantity Total Incentive
COUNTY OF SANTA BARBARA Level 2 60 $150,000.00
TOTAL 60 $150,000.00
Table 1: Charge Your Fleet projects awarded in FY 2024-25.

Electrify Your Fleet Program
3CE’s Electrify Your Fleet (EYF) program incentivizes Member Agencies to purchase or lease electric fleet vehicles. Applications are accepted until program funds are spent. 3CE Member Agency applicants are

eligible to be awarded up to $150,000 in EYF incentives in a single program year. In FY 2024-25, 3CE has budgeted $1.1 million for EYF.

In FY 2024-25, EYF has received two applications to date. Staff are actively engaging with Member Agencies who are in the process of purchasing electric fleet vehicles including the City of Carpinteria, City of Goleta, City of San Luis Obispo, City of San Juan Batista, City of Santa Cruz, City of Santa Maria, City of Watsonville, and County of Monterey. 3CE expects increased participation later in the fiscal year as Member Agencies who participated in FY 2023-24's Plan Your Fleet program implement their plans.

Member Agency Equipment Type Quantity Total Incentive
CITY OF SANTA MARIA Battery Electric Vehicle 2 $10,000.00 TOTAL 2 $10,000.00
Table 2: Electrify Your Fleet projects awarded in FY 2024-25.

EV Charger Asset Pilot
The EV Charger Asset Pilot will improve access to public and workplace charging through 3CE owned and operated Level 2 EV chargers and Direct Current Fast Chargers.

On December 11, 2024, the Policy Board approved an EV Charger Asset Pilot at 3CE’s offices located at 1026 Palm Street in San Luis Obispo. The project will include five parking spaces serviced by three L2 charging stations. The EV charging stations at the 1026 Palm Street office parking lot will allow 3CE to evaluate workplace charging and possible synergies with innovative energy management approaches such as vehicle-to-load charging. Staff recently received a grant from the SLO APCD to cover approximately 60% of equipment purchase and installation costs. Construction is expected to begin in the coming weeks.

BUILDING ELECTRIFICATION
Electrify Your Home Program
The Electrify Your Home (EYH) program provides incentives to contractors enrolled in the TECH Clean California (TECH) program for installation of all-electric heat pump water heating and HVAC systems in existing single and multi-family buildings. EYH reduces purchase costs to 3CE customers, incentivizing making the switch to all-electric heat pump technology. The FY 2024-25 budget for EYH is $720,000

Contractors enrolled in TECH are provided education and training on electrification design and specifications, heat pump installation, building science, and sales and marketing for electric heat pumps at no cost. There are currently 75 licensed contractors enrolled in the TECH program that work in 3CE’s service area.

On November 13, 2024, the Operations Board approved an amendment to 3CE’s contract with Energy Solutions, 3CE’s program administrator for Electrify Your Home. The amendment increased the not-to-exceed amount listed in the contract by $990,000 and extended the term of the agreement by eight months to allow for continued and uninterrupted services to support Electrify Your Home through the end of FY 2024-25.

In FY 2024-25, the EYH program distributed $428,250 in rebates to promote the installation of 85 Heat Pump HVAC units and 44 Heat Pump Water Heater Units.
3CE County Heat Pump HVAC
Units Installed
Heat Pump Water
Heater Units Installed
MONTEREY 27 17
SAN LUIS OBISPO 1 9
SANTA BARBARA 1 13
SANTA CRUZ 56 5
Table 2: Electrify Your Home installations by county.
3CE staff are actively collaborating with the Community Advisory Council to host community listening sessions to gather feedback on the current Electrify Your Home Program and potential improvements to the program’s design. Two listening sessions were hosted in November, and two additional listening sessions are scheduled in April. Community feedback from the events will inform future program improvements for Electrify Your Home across five program design focus areas: Awareness, Evaluation, Installation, Rebates, and Post-Install Monitoring.

New Construction Electrification Program
The New Construction Electrification Program (NCEP) provides housing developers and homeowners with incentives to build all-electric single and multifamily housing, including market- rate, affordable,

farmworker, and disaster -rebuild housing types as well as Accessory Dwelling Units (ADUs). Qualifying projects must be fully electric including appliances for space heating, water heating and cooking. The FY 2024-25 budget for NCEP is $1.0 million.

So far in FY 2024-25, the program has distributed $455,000 across four counties to support construction of 165 units.
3CE County
Market-Rate
Housing
Affordable
Housing
Accessory
Dwelling Units
(ADUs)
Disaster
Rebuilds
Total Units
Incentivized
Monterey - - 2 - 2

SAN BENITO - - - - -
SAN LUIS OBISPO - - 4 - 4
SANTA BARBARA - - 4 - 4
SANTA CRUZ - 152 2 1 155
Table 3: All-electric construction supported via NCEP in FY 2024-25.

Reach Code Program
3CE’s Reach Code program launched October 1, 2022, providing local cities and counties no-cost technical assistance to help adopt and implement reach codes, including stakeholder outreach support. Services include presenting to key stakeholders, technical consultation, developing customized ordinances, reviewing staff presentations and reports, and developing implementation tools to help Member Agencies enforce reach codes. In FY 2024-25, 3CE has budgeted $150,000 for the Reach Code program.

So far in FY 2024-25, 3CE is providing Reach Code assistance to the following Member Agencies:

Member Agency Reach Code Type
City of Goleta New Construction (complete)
City of San Luis Obispo Existing Buildings (underway)
City of Santa Cruz Existing Buildings (underway)
Table 4: Reach Codes participation in FY 2024-25.

AGRICULTURAL ELECTRIFICATION
Agricultural Electrification Program
3CE’s Agricultural (Ag) Electrification program provides rebates to agricultural customers for replacing fossil fuel powered equipment with electric powered alternatives including farm tools, irrigation pumps, vehicles, and more. Enhanced incentives are available for small businesses and for businesses replacing equipment damaged or destroyed by a declared natural disaster. The program also offers technical assistance for EV infrastructure buildout at agricultural customer sites. The FY 2024-25 budget for Ag Electrification is $800,000.

Rebates for equipment with higher estimated GHG emissions avoidance and those benefiting small to medium sized agricultural businesses are supported with greater incentive levels. 3CE covers up to 50% of the cost for ag equipment, providing up to $15,000 for smaller “Tier 1” equipment and up to $75,000 for larger “Tier 2” equipment. Program funds are offered as a post-purchase rebate, with up to two rebates per customer per fiscal year.

So far in FY 2024-25, 3CE has distributed $302,870.55 in rebates to support eight equipment purchases.

These rebates have helped enable over $730,000 in all-electric agricultural equipment.

Electric Ag Equipment Qty Incentivized Recipients
Excavator 2  Bee Farm in County of Santa Barbara
 Winery in County of Santa Cruz
Tractor (standard) 4  Winery in County of Monterey
 Flower Farm in County of Santa Barbara
 Ranch in County of San Benito
 Avocado Orchard in County of Santa Cruz
Forklift 1  Farm in County of San Benito
Irrigation Pump 1  Farm in County of Monterey
Table 5: Agricultural Electrification projects awarded in FY 2024-25. 100% of Agricultural Electrification Program incentives distributed so far in FY 2024-25 have been to small businesses who are 3CE customers.

County % of incentives distributed to small businesses
SAN BENITO 100%
SAN LUIS OBISPO 0%
SANTA BARBARA 100%
SANTA CRUZ 100%
MONTEREY 100%
TOTAL 100%
Table 6: Agricultural Electrification projects awarded to small businesses in FY 2024-25.

DEMAND RESPONSE / LOAD MANAGEMENT
Residential Battery Rebate Program
3CE’s Residential Battery Rebate program launched on July 16, 2024, to incentivize use of residential behind-the-meter battery storage systems. Rebates are provided for purchase of eligible batteries, qualifying installation hardware, and labor directly related to the battery system's installation. 3CE has set a goal of issuing four hundred rebates per fiscal year, which equates to approximately 2.6 megawatts (MW) of load shifted, and an annual expenditure of $2M.

The program offers a $300 per kilowatt hour (kWh) base rebate for customers. A $500 per kilowatt hour (kWh) rebate is offered to Net Energy Metering (NEM) 1.0 and NEM 2.0 tariff customers who elect to transition to Net Billing Tariff (NBT) early. Additionally, the program offers a $500 per kilowatt hour (kWh) rebate for customers who are enrolled in the Medical Baseline program and are reliant on electricity to power medical devices. To promote adoption in disadvantaged and low-income communities, the program also offers a $500 per kilowatt hour (kWh) rebate for customers enrolled in CARE or FERA payment assistance programs.

In February 2025, staff introduced a new scheduling assistance service to help customers set their battery systems to discharge during peak hours of 4:00 pm to 9:00 pm. In its first week, eight customers have already signed up to receive assistance. Staff are conducting direct outreach to rebate applicants to ensure they meet the Program’s discharge requirements.

As of February 2025, 3CE has received 158 applications for the program. Since launching, 3CE has distributed $193,500 in rebates to customers, with approximately 278 kWh of load shifted daily during the peak period of 4:00 pm to 9:00 pm.

Figure 4 (above): kWh of load shifted daily during the peak period of 4:00 pm to 9:00 pm per month.

Staff will present a report on the program’s performance over its first six months to the Community Advisory Council, Operations, and Policy Boards in 2025.

Hourly Flex Pricing Pilots 1 and 2
3CE, in partnership with PG&E and its vendors, has officially launched the Hourly Flex Pricing Pilot. The program offers eligible agricultural, commercial, and residential customers a way to lower their energy costs by locking into hourly energy prices forecasted up to one week in advance, then shifting load accordingly, which will be tracked on a monthly performance bill. At the end of each 12-month participation period, any total cost savings through hourly price-based load shifting would be credited to the customer via a check from 3CE.

The Hourly Flex Pricing Pilot 1 will be for agricultural 3CE customers and will include a one-time rebate for purchasing automation technology and software that responds to price signals, such as a controller for an irrigation pump.

The Hourly Flex Pricing Expanded Pilot 2 will be for commercial and residential customers. To date, 3CE has received over 10 residential applications, six of which are now officially a part of Expanded Pilot 2.

OTHER STRATEGIC INITIATIVES
Customer Relationship Management System Integration
The new Customer Relationship Management (CRM) tool for program applications and management was successfully launched on October 1st, 2024. Existing program applications were kept open during the transition from FY 2023-24 to the current fiscal year. Additional usability features for 3CE are under development.

Staff Report Item 4
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Jerri Strickland, Director of Regulatory Affairs and Compliance Das Williams, Senior Advisor of Policy and Legislative Affairs SUBJECT: Regulatory and Legislative Quarterly Update
DATE: March 19, 2025
RECOMMENDATION:

This memorandum provides the Policy Board with a quarterly Regulatory & Legislative Update.

DISCUSSION:

These quarterly updates prepare a summary of key regulatory proceedings and legislative matters impacting 3CE’s customer support, business operations, and climate goals.

FISCAL IMPACT:

No financial impact by receiving this report.

ATTACHMENT(S):

1. Quarterly Regulatory and Legislative Update

Quarterly Regulatory & Legislative Update
March 19, 2025

Table of Contents
REGULATORY UPDATE ..............................................................................................................................3 Resource Adequacy (RA) -.........................................................................................................................3 Provider of Last Resort (POLR) and Emergency Transition Planning –.....................................................3 Load Management Standards (LMS) and Real-Time Pricing -...................................................................4 New Power Charge Indifference Adjustment (PCIA) Rulemaking –..........................................................4 Integrated Resource Planning (IRP) -........................................................................................................5 Interconnections -.....................................................................................................................................6 PG&E Rule 30 Application for Transmission Service –..............................................................................6 Energy Resources Recovery Account (ERRA) Forecast – ..........................................................................7 General Rate Cases...................................................................................................................................8 3CE LEGISLATIVE REPORT – Q1 2025 ........................................................................................................9 2025 Session Overview: ............................................................................................................................9 Budget:......................................................................................................................................................9 Priority Bill Updates: ...............................................................................................................................10

REGULATORY UPDATE
Resource Adequacy (RA) - R.23-10-011
Issue
The Resource Adequacy (RA) program is the California Public Utilities Commission’s (CPUC) main grid reliability planning program. All load serving entities (LSEs) under the CPUC’s jurisdiction, including CCAs, must demonstrate purchase of a specified amount of eligible RA generation capacity each month and year to comply with RA program requirements. Increasing demand for and a decreasing supply of eligible RA capacity over the past five years have resulted in sharply increased prices and unprecedented difficulty procuring sufficient RA to achieve compliance. Over the past year the CPUC has also sought to tie RA compliance to other, unrelated functions such as CCA expansion into new communities.

Status
Parties have submitted Track 3 RA proposals addressing a wide range of topics, including modifications to the new 24-hour requirement counting method called the Slice-of-Day framework, the Planning Reserve Margin (PRM) for 2026 and 2027 which is the amount of energy needed to be procured in excess for reliability called the, accreditation of long duration energy storage resources, and approaches to an unforced capacity (UCAP) methodology to account for historical forced outage rates in RA capacity values for certain resources. 3CE worked with CalCCA to develop Track 3 proposals to reintroduce hourly load obligation trading and formalize counting rules for co-located resources. 3CE staff are actively attending CPUC directed RA workshops to better understand the revised 2026 PRM study and proposals under consideration in Track 3.

Next Steps
3CE staff are currently drafting independent comments, due March 17, to urge the Commission to support proposals that increase reliability and prioritize customer affordability, maintain the current PRM rather than increasing it without a robust analysis, and to revise its current study to address errors identified by stakeholders. The CPUC will issue a proposed Track 3 decision in May, with a final adoption set for June.

Provider of Last Resort (POLR) and Emergency Transition Planning – R.21-03-011 Issue
The Provider of Last Resort (POLR) is the backstop entity that provides electric service to customers of a load serving entity if that LSE fails suddenly. This role has historically been held by the investor-owned utilities (IOUs, namely Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric), but this proceeding is establishing a process to allow CCAs and other non-IOU LSEs to become POLR in their service areas. 3CE does not aim to be the POLR but wants to ensure the process is fair for all LSEs and avoids competitive issues. This proceeding also considers rules designed to prevent LSE failures that have various implications for 3CE finances and operations. This includes changes to how much money CCAs must post as insurance against their own failure (called the Financial Security Requirement or FSR).

Status
Phase 2 of the proceeding consist of two tracks: the first will address primary threshold questions regarding the authority of the CPUC and non-IOU POLRs, while the second will focus on the regulatory framework and application process for non-IOU entities to become POLRs. Party comments in Phase 2 have indicated that no non-IOU entity is currently interested in taking on the POLR role, so CalCCA is advocating that the CPUC defer decisions on granular issues until parties express interest in transferring POLR obligations. CalCCA opposes stakeholder arguments that propose broader CPUC authority over a

non-IOU POLR and advocates that if the CPUC does intend to issue a decision on jurisdictional questions, legal briefs should be required.

Next Steps
3CE is monitoring the proceeding for the CPUC’s issuance of a Ruling on threshold issues and determination on whether legal briefs are needed in Q1 or Q2 of 2025. 3CE and CalCCA will continue to advocate for the legislatively protected autonomy of CCAs.

Load Management Standards (LMS) and Real-Time Pricing - 23-LMS-01 Issue
The California Energy Commission’s (CEC) updated Load Management Standard (LMS) regulations now require IOUs, municipal utilities, and CCAs with load greater than 700 GWh/year to upload time-dependent rates to the CEC’s Market Informed Demand Automation Server (MIDAS) platform, develop an LMS Compliance Plan (LMS Plan) by March 2024, and present to their governing bodies, for approval by the CEC, at least one hourly marginal cost based rate option (often referred to as a real-time rate) for their customers by 2025. The LMS requirements also request the LMS LSEs to create a Single-Statewide Tool (SST) for customers to be able to compare and change rates.

Status
In February 2024, 3CE’s Policy Board approved 3CE’s LMS Plan. In early February 2025, 3CE met with the CEC, which commended 3CE’s programs for shifting load to more affordable and lower-emission times.

The CEC has provided both informal and formal pathways for CCAs to update LMS Plan. 3CE expects a formal request for minor updates and revisions to the Plan by Q2 2025. 3CE’s CEO, along with other CCA CEOs, have had ongoing dialogue with CEC Commissioner J. Andrew McCallister to advocate for a measured approach to LMS regulations, cautioning that overly stringent requirements may hinder innovation.

Next Steps
3CE is monitoring for the formal request to update its LMS Plan, which will be issued within the CEC’s LMS docket. 3CE will respond with an update to its Plan within 90 days of the request.

New Power Charge Indifference Adjustment (PCIA) Rulemaking – R.25-02-005 Issue
On February 20, the CPUC opened a new proceeding to update policies and procedures related to the IOUs’ Energy Resource Recovery Accounts (ERRA) and the Power Charge Indifference Adjustment (PCIA).

The PCIA is a fee that all customers, bundled or unbundled, pay to ensure the IOUs remain indifferent to the loss of customers for legacy procurement done prior to customers having the choice to choose their energy provider. The rulemaking will address near- and long-term changes impacting the PCIA, a ratemaking element designed to ensure customer indifference to retail load departure. The CPUC calculates the PCIA using market price benchmarks (MPBs) to establish the market value of the IOUs’ PCIA-eligible portfolio. However, in recent ERRA proceedings, the IOUs have proposed new policies related to the calculation of MPBs, citing concerns with the accuracy and volatility of the current methodology.

Status
Track 1 is reviewing potential modifications to MPB calculations, aiming for a May 2025 decision for inclusion in 2026 ERRA forecasts. Proposed changes include adjusting transaction data, considering

monthly or seasonal MPBs, and consolidating RA attributes into a single MPB calculation. Track 2 will focus on broader, long-term improvements to ERRA and PCIA processes, IOU rate forecasts, and mitigating rate volatility.

Next Steps
3CE is assisting CalCCA draft comments on the Order Instituting Rulemaking (OIR) due March 17. The comments will center the need for the Commission to administer the PCIA fairly and accurately as it is their obligation to ensure a level-playing field among LSEs.

Integrated Resource Planning (IRP) - R.20-05-003
Issue
Integrated Resource Planning (IRP) is the CPUC’s greenhouse gas (GHG) reduction planning program.

LSEs must submit IRPs every two years demonstrating that planned future procurement will produce GHG emissions below an assigned benchmark while contributing to a resource fleet that meets sector wide GHG targets and maintaining grid reliability. Previous IRP cycles have produced three procurement mandates, which apply to 3CE and other CCAs. The CPUC’s Amended Scoping Memo outlines plans to address additional issues in the IRP proceeding, including the implementation of Assembly Bill (AB) 1373, which allows the Commission to request the Department of Water Resources (DWR) serve as a central procurement entity for long-lead time (LLT) resources, and the development of the Reliable and Clean Power Procurement Program (RCPPP) to replace the current ad hoc mandate structure.

Status
The CPUC voted to approve the 2025-2026 Transmission Plan Portfolios (TPPs) for use by CAISO in determining needed upgrades or additions to the transmission system. The Decision adopts two portfolios; a base case with approximately 63 GW of new storage and clean energy to come online by 2035 and a sensitivity portfolio that incorporates the maximum amount of long lead time (LLT) resources ordered for DWR procurement. The Decision requests that CAISO reserve deliverability for the full amount of geothermal, biomass, offshore wind, and non-battery long-duration energy storage (LDES) resources in the base case and recommends that CAISO study, but not yet implement, solutions to bring out-of-state wind resources into the CAISO balancing area. CPUC President Alice Reynolds also requested DWR to exercise its CPE function for LLT Resources with solicitations beginning in late 2026.

Separately, the LDES Council filed a Petition for Modification (PFM) to the CPUC’s mid-term reliability (MTR) decision (D. 21-06-035) that ordered procurement of LLT resources including LDES, requesting language to clarify that LSEs may not meet the LDES requirement by reducing the full potential maximum capacity of a storage resource and extending the delivery period. While the PFM would not impact 3CE’s compliance with the MTR order, 3CE worked with CalCCA to develop comments opposing the PFM given the original decision language is unambiguous and changes to a 2021 decision now would constitute retroactive rulemaking.

Next Steps
If the results of CAISO’s base case analysis show the need for additional transmission, CAISO will submit projects for approval by its Board of Governors in Spring of 2026. 3CE anticipates the Commission to respond to the LDES PFM and publish the RCPPP within Q1 or early Q2 of 2025. Internally, 3CE is initiating work on its next IRP filing, due to the CPUC on November 1, 2025. The IRP filing will outline 3CE’s procurement planning for the next 10 years and how 3CE will achieve or exceed mandated GHG-reduction targets.

Interconnections - IPE 2023
Issue
The California Energy Commission’s (CEC) 2023 Integrated Energy Policy Report (IEPR) identifies interconnection delays as a significant barrier to achieving California’s electrification and decarbonization goals. Ongoing initiatives led by various entities are working to address this issue and streamline processes for connecting clean resources to the grid. One such effort is CAISO’s 2023 Interconnection Process Enhancements (IPE) initiative, focused on enhancing coordination of resource procurement, interconnection, and transmission planning to achieve state reliability and policy needs.

Status
CAISO has published its final proposal for Track 3 of the IPE initiative, which modifies the process for allocating Transmission Plan Deliverability (TPD) to resources that support resource adequacy. The proposal prioritizes TPD for projects with signed Power Purchase Agreements (PPAs) and offers a pathway for projects without PPAs to receive conditional allocations. Despite stakeholder opposition, the proposal eliminates opportunities for energy-only (EO) projects to seek deliverability beyond pre-cluster 15 projects. In response to CalCCA’s request to allow EO projects to submit new interconnection requests after achieving commercial operation, CAISO defers this consideration to a future IPE initiative.

Next Steps
CAISO will seek approval for Track 3 IPE initiatives from the CAISO Board of Governors on March 27. If approved, the new TPD allocation process would begin in 2027.

PG&E Rule 30 Application for Transmission Service – A.24-11-007 Issue
On November 21, 2024, PG&E submitted an Application to the CPUC requesting approval of a new rule for non-residential customers requesting interconnection at transmission-level voltages, citing a recent increase in customers such as data centers requesting transmission-level interconnections. Current PG&E rules are focused on distribution-level interconnections. Under the proposed rule, the transmission-level customer would pay interconnection costs in advance until their forecasted load materializes, at which point the costs would be collected through rates. 3CE has spearheaded a joint CCA coalition to participate in the proceeding to ensure that any resulting rule change supports affordability, maintains competitive neutrality, and equitable treatment of all interconnection requests.

Status
3CE and 5 other CCAs (Joint CCAs) have engaged with PG&E’s Application to raise important issues for consideration within the proceeding, including safeguards against PG&E’s inherent market power advantages, collaboration with CCAs, affordability, and cost allocation. The Commission issued a scoping ruling setting an anticipated Decision by March 2026. Concurrently, PG&E has filed a Motion for an Interim Implementation of Rule 30 prior to a Final Decision on the original Application. The Joint CCAs have commented on the Motion that PG&E has not shown an extraordinary need to implement Rule 30 prior to a full Commission review.

Next Steps
Testimony will be due June 30. In the meantime, Joint CCAs continue to work with PG&E to address the primary concerns of customer equity considerations, competitiveness issues, and data sharing needs for grid reliability.

Energy Resources Recovery Account (ERRA) Forecast – A.24-05-009; A.24-05-007 Issue
ERRA forecast applications are filed annually by IOUs to look ahead at energy procurement-related revenue requirements, including the allocation of costs across Power Charge Indifference Adjustment (PCIA) vintages. CCAs participate through CalCCA to ensure: (1) accuracy of forecast account balances, rates, and cost calculations; (2) proper attribution of PCIA vintage; (3) proposer attribution between bundled and unbundled customers; (4) appropriateness of IOU proposals within the context of an ERRA forecast proceeding.

PG&E Status:

The CPUC approved the Revised PD in PG&E’s ERRA Forecast proceeding on December 19, 2024. The revisions did not impact the CCA’s key concerns, which were to prevent the adoption of PG&E’s RA and RPS market-price benchmark (MPB) mitigation proposals and to secure the CPUC's approval of CalCCA’s common cost allocation proposal. President Reynolds highlighted that IOU rate decreases would result in semi-annual climate credits for customers in 2025, ranging from $112 to $162. PG&E filed its final Annual Electric True-up (AET) Advice Letter on December 30, 2024, reflecting trued-up 2024 costs and the new rates effective January 1, 2025. The AET revealed a 0.7% decrease in PG&E's bundled system average rates and a 2.8% decrease in delivery rates. CalCCA has requested work papers from PG&E to further analyze the impacts on the PCIA and will share this information with PG&E CCAs.

CalCCA’s key issues in the proceeding were (1) avoid a structural change to MPBs for RA and RPS, and (2) advocating against the adoption of a common cost allocation proposal to distribute administrative generation costs across PCIA vintages by gross revenue requirement. The CPUC's first PD, issued on November 25, 2024, rejected structural changes to the MPBs, which would have added ~$1 billion in costs to the PCIA. The PD did adopt a common cost allocation proposal but agreed with CalCCA that it should not apply to 2024 costs. CalCCA filed Comments on December 2, 2024, supporting the rejection of MPB changes and opposing the approval of its common cost allocation proposal. CalCCA filed Reply Comments on December 5, 2024, refuting claims about cost shifts and reiterating its stance on excluding the new cost allocation methodology from 2024.

SCE Status:

The CPUC approved a revised PD for SCE’s ERRA Forecast at its December 19, 2024, voting meeting, with President Reynolds noting IOU rate decreases and semi-annual climate credits for customers in 2025 ranging from $112 to $162. SCE submitted its final AET on December 30, 2024, implementing the Final Decision and new rates starting January 1, 2025. SCE’s bundled system average rate increased by 0.3%, and CalCCA is requesting workpapers to further analyze the impacts on the PCIA. The SCE CCAs’ and CalCCA’s key issues were the rejection of two SCE proposals: (1) the RA Categorization Proposal, which would categorize RA retained for system use at the lower local RA MPB, and (2) the SOD RA Valuation Proposal, which adjusts how RA quantity is calculated in valuing SCE’s PCIA RA portfolio.

The CPUC issued an initial PD on November 25, 2024, with mixed outcomes. While the CPUC sided with SCE on the RA Categorization Proposal, CalCCA argued that the categorization did not align with how RA is used, and the PD lacked analysis explaining the rationale behind the decision. The CPUC stated that further changes to RA MPBs would be considered in a future rulemaking. On the SOD RA Proposal, the CPUC adopted it, agreeing with CalCCA that it benefits CCA customers. CalCCA filed Comments on December 2, 2024, recommending that the RA Categorization Proposal be rejected, or if adopted, applied only prospectively or up to SCE’s CPE local procurement obligation. CalCCA did not file Reply

Comments, while SCE responded by defending retroactive ratemaking in the RA Categorization Proposal, citing a 1978 case that may complicate future decisions on RA.

Next Steps
3CE and CalCCA will continue to address MPB reform proposals raised in the SCE & PG&E 2025 ERRA Forecast cases in the new PCIA Rulemaking (R. 25-02-005) at the CPUC. The 2025 ERRA Forecast Cases are now closed and PG&E and SCE will file their next Forecast Applications for their 2026 generation rates in May of 2025.

General Rate Cases — A.24-09-014; A.24-03-019
Issue
In four-year cycles, the IOUs submit General Rate Case (GRC) applications to adjust rates and charges for electric and gas service. The CPUC conducts GRCs in two phases, using Phase I to set the total amount each IOU is authorized to collect and Phase 2 to determine the cost allocation and rate schedules for each customer class. All CCAs participate jointly in GRCs through CalCCA to advocate for just and reasonable IOU rate design and transparent customer bill presentment.

PG&E Status
PG&E submitted its GRC Phase 2 Application which proposes to increase its fees for services provided for CCAs and requests the ability to update these fees more frequently through Tier 2 Advice Letters rather than within the four-year GRC cycle. Eight parties submitted protests to PG&E’s application. The primary CCA issues identified within PG&E’s proposal are the escalation of CCA service fee costs, PG&E’s POLR administrative cost, and a proposal to allow inter-GRC cycle applications for future changes to CCA service fees via Tier 2 advice letter. CalCCA and the PG&E CCAs will work with consultants to further investigate the method for increasing CCA service fees.

SCE Status
No update.

Next Steps
Parties are awaiting a PD in SCE’s Phase I GRC, which has no CCA contested issues, by Q1 2025 and an Initial Scoping Memo for PG&E’s Phase II Application. Once the scope is determined, 3CE will work with CalCCA to investigate the reasonableness for PG&E to increase CCA service fees.

3CE LEGISLATIVE REPORT – Q1 2025
2025 Session Overview:

The 2025-26 California legislative session is in full swing. The legislature is now fully turned over from the first class under the 2012 term-limits “shortening” (to 12 years). That new class is entering the legislature at a time of significant challenges. Early estimates indicate the LA wildfires will be the costliest natural disaster in the history of the country, and with a hostile federal administration overseeing disaster relief funds, it is unclear how much of the recovery costs California will have to shoulder alone. California has already appropriated $2.5 billion for initial clean up and recovery actions, but there will be significant funding needs in the coming months and years.

Moreover, the Trump administration is acting swiftly to defund different programs and services, including those related to climate and clean energy investments. Shortly after Trump won the November election, Governor Newsom announced a legal defense strategy that would be carried out by Attorney General Rob Bonta to protect California and the money the state receives from the federal government. A special session was launched to immediately route $25M to the Attorney’s General office to carry out this vision; that money has since been appropriated and we are already seeing lawsuits from the Attorney General blocking certain actions from the federal administration. We expect this legal defense to develop in the coming months and years.

Budget:

On January 10th, the Governor released his proposed budget which the legislature will have the opportunity to review and amend in the coming weeks and months. The Governor proposes a $322.3 billion budget, which includes $228.9B from the General Fund and $16.9B in total revenues. The Governor’s Department of Finance estimates a $363M surplus, compared to the Legislative Analyst's Office’s -$2B estimation.

The Governor’s Office has outlined a number of risks to California’s current budget cycle, including stock market volatility and declines, uncertainty about federal policy, elevated or re-emerging inflation and subsequent restrictive monetary policy, and delayed tax deadlines due to LA wildfires. The legislature has already begun negotiating the budget through various budget committee hearings and stakeholder discussions.

Friday, February 21st marked the deadline for legislation to be introduced in the legislature. There are a few relevant clear themes already apparent: energy affordability and infrastructure are in square focus for this legislative cycle. Below are the top bills 3CE is currently tracking:

Priority Bill Updates:

Battery storage policy in response to Moss Landing
 AB 303 (Addis)- Battery Energy Storage Facilities
 AB 434 (DeMaio)- Construction and safety standards: battery storage facilities  AB 1285 (Committee on Emergency Management)-State Fire Marshal: lithium-ion battery facilities: guidance
 SB 283 (Laird) - Battery energy storage facilities: emergency response plans and emergency action plans
Regional Electricity Markets:
 SB 540 (Becker)- Independent System Operator- Independent Regional Market Transmission and Infrastructure Streamlining:
 AB 745 (Irwin) Electricity: transmission projects: review and approval  AB 854 (Petrie-Norris) AB-854 Environmental quality: greenhouse gas emissions: permit streamlining
 AB 941 (Zbur) California Environmental Quality Act: electrical infrastructure projects  SB 331 (Padilla) State Energy Resources Conservation and Development Commission:
certification of facilities: electrical transmission projects The most significant of these is SB 540, which would create a framework for regional energy co-operation dubbed Pathways. Regionalization could lower long-term costs and increase reliability while facilitating the oversupply of CA solar to find out of state markets. This proposal includes protections for the state’s clean energy goals that bring many labor and environmental in support that were previously opposed.

Staff Report Item 5
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Gina Urmatan, Senior Accountant
SUBJECT: Financial report for the period October 1, 2024, through December 31, 2024 DATE: March 19, 2025
RECOMMENDATION:

Receive a financial report for the period of October 1, 2024, through December 31, 2024.

SUMMARY:

Over the three months ending December 31, 2024, operating revenues amounted to $136.1 million, and operating expenses totaled $106.1 million for a net operating income of $30.0 million. Non-operating revenue of $2.4 million, driven by interest and investment returns, netted the month with a net position increase of $32.4 million.

Year-to-date operating revenue is $15.8 million lower than budget, primarily due to lower-than-expected retail load. 3CE is actively monitoring retail load projections and will adjust the forecast downward as part of the proposed rate recommendation for Policy Board approval at its March 19 meeting. This adjustment is based on a comparison of the prior year's forecast versus actual results, as well as year-to-date actuals. Non-operating revenue from investment returns from assets held in operating and investment accounts and interest on collateral exceeded the budget with a positive variance of $0.7 million, resulting from a favorable short-term interest rate. Year-to-date total revenue is $15.1 million lower than budget, an unfavorable variance of 10%.

Year-to-date operating expenditures are lower than the budget by $27.8 million, a variance of 21%. The cost of energy was $22.8 million lower than the budget primarily due to the timing of invoicing for regulatory compliance for renewable energy attributes, Renewable Energy Certificates (RECs) and higher credits for effective participation in the congestion revenue rights (CRR) process managed by the California Independent System Operator (CAISO). Non-energy operating costs were $5.0 million lower

than budget due to less-than-planned costs for contracted services, energy programs, and staff vacancies.

The capital outlay was below budget by $4.3 million since capital projects are not recorded as direct expenditures. Instead, they are recorded as capital assets on the balance sheet and expensed over time through depreciation in accordance with accounting principles. Year-to-date total expenditures, including capital outlay, are $32.1 million lower than budget, a variance of 23%. These variances are expected to level out over the fiscal year as 3CE fulfills its energy obligations, including resource adequacy (RA) and renewable energy credits (RECs). Additionally, higher energy costs are anticipated due to the enrollment of the City of Atascadero and the County of San Luis Obispo that began in January 2025.

The net position at the end of December 31, 2024, totaled $250.6 million, a $32.4 million increase from the start of the fiscal year. The increase is primarily due to the increased cash and investments, collateral receipts from suppliers, and reduced accrued cost of electricity. Cash, cash equivalents, and short-term investments totaled $216.3 million, a $10.4 million decrease during the reporting period. The decrease corresponds to an increase in deposits held by energy counterparties from the posting of collateral on contracts. The need for increased collateral was driven by heightened exposure levels, leading to higher margin requirements.

FISCAL IMPACT:

There is no financial impact associated with receiving this report.

ATTACHMENT(S):

1. December 31, 2024 Financial Report

FINANCIAL REPORT
Fiscal Year to Date
As of December 31, 2024

1 ACCOUNTANTS’ COMPILATION REPORT
Board of Directors
Central Coast Community Energy
Management is responsible for the accompanying financial statements of Central Coast Community Energy (a California Joint Powers Authority) which comprise the statement of net position as of December 31, 2024, and the related statement of revenues, expenses, and changes in net position, and the statement of cash flows for the three months then ended in accordance with accounting principles generally accepted in the United States of America. We have performed a compilation engagement in accordance with Statements on Standards for Accounting and Review Services promulgated by the Accounting and Review Services Committee of the AICPA. We did not audit or review the accompanying statements nor were we required to perform any procedures to verify the accuracy or completeness of the information provided by management. Accordingly, we do not express an opinion, conclusion, nor provide any assurance on these financial statements.

Management has elected to omit substantially all of the note disclosures required by accounting principles generally accepted in the United States of America in these interim financial statements.

Central Coast Community Energy’s annual audited financial statements include the note disclosures omitted from these interim statements. If the omitted disclosures were included in these financial statements, they might influence the user’s conclusions about the Authority’s financial position, results of operations, and cash flows. Accordingly, these financial statements are not designed for those who are not informed about such matters.

We are not independent with respect to the Authority because we performed certain accounting services that impaired our independence.

Maher Accountancy
San Rafael, CA
January 28, 2025
1101 Fifth Avenue, Suite 200 San Rafael, CA 94901 415 459 1249 mahercpa.com

Current assets
Cash and cash equivalents 113,175,025$
Accounts receivable, net of allowance 40,621,574
Accrued revenue 30,837,147
Other receivables 2,244,165
Investments 95,666,281
Prepaid expenses 1,494,774
Deposits 41,257,318
Loan receivable 192,501
Total current assets 325,488,785
Noncurrent assets
Investments 7,489,109
Deposits 23,182
Loan receivable 1,233,381
Capital assets, net of depreciation and amortization 3,723,735 Total noncurrent assets 12,469,407
Total assets 337,958,192
Current liabilities
Accrued cost of electricity 51,752,875
Accounts payable 1,635,357
Other accrued liabilities 1,571,003
User taxes and energy surcharges due to other governments 1,957,634 Security deposits - energy suppliers 19,089,299
Lease liability 331,665
Total current liabilities 76,337,833
Noncurrent liabilities
Security deposits - energy suppliers 10,303,125
Lease liability 757,373
Total noncurrent liabilities 11,060,498
Total liabilities 87,398,331
Net investment in capital assets 2,634,697
Unrestricted 247,925,164
Total net position 250,559,861$

NET POSITION
As of December 31, 2024

STATEMENT OF NET POSITION

CENTRAL COAST COMMUNITY ENERGY
ASSETS

LIABILITIES

OPERATING REVENUES
Electricity sales, net 136,052,467$
Other income 20,043
Total operating revenues 136,072,510

OPERATING EXPENSES
Cost of electricity 98,616,642
Contract services 3,394,486
Staff compensation 2,253,041
Other operating expenses 505,441
Program incentives 1,195,965
Depreciation and amortization 156,516
Total operating expenses 106,122,091
Operating income (loss) 29,950,419

NONOPERATING REVENUES (EXPENSES)
Investment income 2,456,836
Interest and financing costs (12,837)
Nonoperating revenues (expenses) 2,443,999
CHANGE IN NET POSITION 32,394,418
Net position at beginning of period 218,165,443
Net position at end of period 250,559,861$
Three Months Ended December 31, 2024

AND CHANGES IN NET POSITION

STATEMENT OF REVENUES, EXPENSES

CENTRAL COAST COMMUNITY ENERGY

CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from customers 142,508,875$
Other operating receipts 5,458,367
Receipts of deposits and collateral 28,374,860
Payments to suppliers for electricity (125,882,645)
Payments for deposits and collateral (38,868,775)
Payments for other goods and services (4,240,163)
Payments for program incentives (3,483,300)
Payments for staff compensation (2,039,888)
Payments of taxes and energy surcharges to other governments (2,548,218) Net cash provided by operating activities (720,887)

CASH FLOWS FROM CAPITAL AND RELATED

FINANCING ACTIVITIES
Payments of lease liability (90,749)
Purchases of capital assets (50,138)
Net cash provided (used) by capital and related financing activities (140,887)

CASH FLOWS FROM INVESTING ACTIVITIES
Investment income received 1,509,918
Proceeds from sales and maturities of investments 21,209,000 Principal payments received of loan receivable 94,915
Purchase of investments (59,316,715)
Net cash provided (used) by investing activities (36,502,882) Net change in cash and cash equivalents (37,364,656)
Cash and cash equivalents at beginning of year 150,539,681 Cash and cash equivalents at end of period 113,175,025$ Three Months Ended December 31, 2024

STATEMENT OF CASH FLOWS

CENTRAL COAST COMMUNITY ENERGY

Operating income (loss) 29,950,419$
Adjustments to reconcile operating income (loss) to net cash provided by operating activities
Depreciation and amortization expense 156,516
(Increase) decrease in:

Accounts receivable, net of allowance 3,816,321
Accrued revenue 111,381
Other receivables 4,146,128
Prepaid expenses 334,450
Deposits (29,664,422)
Increase (decrease) in:

Accrued cost of electricity (25,020,371)
Accounts payable (3,241,869)
Other accrued liabilities 770,073
User taxes and energy surcharges due to other governments (19,514) Security deposits - energy suppliers 17,940,000
Net cash provided by operating activities (720,887)$
Unrealized appreciation (depreciation) and
timing differences in investment income 946,918$

NONCASH INVESTING ACTIVITES

CENTRAL COAST COMMUNITY ENERGY
STATEMENT OF CASH FLOWS (continued)
Three Months Ended December 31, 2024

RECONCILIATION OF OPERATING INCOME (LOSS) TO NET

CASH PROVIDED BY OPERATING ACTIVITIES

1 ACCOUNTANTS’ COMPILATION REPORT

Board of Directors
Central Coast Community Energy
Management is responsible for the accompanying special purpose budgetary comparison schedule of Central Coast Community Energy (a California Joint Powers Authority) for the three months ended December 31, 2024, and for determining that the budgetary basis of accounting is an acceptable financial reporting framework. We have performed a compilation engagement in accordance with Statements on Standards for Accounting and Review Services promulgated by the Accounting and Review Services Committee of the AICPA. We did not audit or review the accompanying statement nor were we required to perform any procedures to verify the accuracy or completeness of the information provided by management. Accordingly, we do not express an opinion, a conclusion, nor provide any assurance on this special purpose budgetary comparison statement.

The special purpose statement is prepared in accordance with the budgetary basis of accounting, which is a basis of accounting other than accounting principles generally accepted in the United States of America. This report is intended for the information of the Board of Directors of the Authority.

Management has elected to omit substantially all of the note disclosures required by accounting principles generally accepted in the United States of America in these interim financial statements.

Central Coast Community Energy’s annual audited financial statements include the note disclosures omitted from these interim statements. If the omitted disclosures were included in these financial statements, they might influence the user’s conclusions about the Authority’s financial position, results of operations, and cash flows. Accordingly, these financial statements are not designed for those who are not informed about such matters.

We are not independent with respect to the Authority because we performed certain accounting services that impaired our independence.

Maher Accountancy
San Rafael, CA
January 28, 2025
1101 Fifth Avenue, Suite 200 San Rafael, CA 94901 415 459 1249 mahercpa.com

Actual Budget Amount % Actual Budget Amount % Budget
Annual Budget
Less Actual
YTD

REVENUES AND OTHER SOURCES
Electricity sales, net $ 44,591,188 $ 52,272,708 $ (7,681,520) -15% $ 136,052,467 $ 151,856,282 $ (15,803,815) -10% $ 745,962,356 $ 609,909,889 Interest and investment returns 841,727 583,333 258,394 44% 2,456,836 1,749,999 706,837 40% 7,000,000 4,543,164 Other income 6,280 5,700 580 10% 20,043 17,100 2,943 17% 68,400 48,357 Total revenues and other sources 45,439,195 52,861,741 (7,422,546) -14% 138,529,346 153,623,381 (15,094,035) -10% 753,030,756 614,501,410 EXPENDITURES AND OTHER USESCurrent Expenditures
Cost of energy 24,971,691 45,746,192 20,774,501 45% 99,100,456 121,944,584 22,844,128 19% 665,267,116 566,166,660 Salaries and benefits 766,047 1,048,820 282,773 27% 2,253,041 3,146,460 893,419 28% 12,585,842 10,332,801 Services and supplies 1,777,551 2,931,483 1,153,932 39% 4,702,828 8,794,448 4,091,620 47% 35,177,798 30,474,970 Capital outlay 14,237 1,443,167 1,428,930 99% 63,219 4,329,500 4,266,281 99% 17,318,000 17,254,781 Total current expenditures 27,529,526 51,169,662 23,640,136 46% 106,119,544 138,214,992 32,095,448 23% 730,348,756 624,229,212 Surplus (deficit) 17,909,669$ 1,692,079$ 16,217,590$ 32,409,802$ 15,408,389$ 17,001,413$ 22,682,000$ (9,727,802)$ Annual

CENTRAL COAST COMMUNITY ENERGY

BUDGETARY COMPARISON SCHEDULE
Current Month and Three Months Ended December 31, 2024
Current Month
Variance
Favorable
(unfavorable)
Year-To-Date
Variance
Favorable
(unfavorable)

CCA Program surplus/(deficit)
per budgetary comparison schedule: 32,409,802$
Adjustments needed to reconcile to the changes in net position in the Statement of Revenues, Expenses and Changes in Net Position:

Add back GASB 87 lease amortization not in operating budget 77,913 Subtract depreciation expense (156,516)
Add back capital asset acquisitions 63,219
Change in Net Position 32,394,418$

REVENUES, EXPENSES AND CHANGES IN NET POSITION

CENTRAL COAST COMMUNITY ENERGY

BUDGET RECONCILIATION TO STATEMENT OF
Three Months Ended December 31, 2024

Budget Item YTD Variance Comment
Electric Sales Revenue (10.6%) Sales revenue includes revenues actually billed to customers as well as estimated customer usage during the reporting period that is not yet billed.

Cost of Energy (18.7%) Variances in this category are typically due to (1) timing difference between projected and actual REC deliveries, (2) variance from actual to anticipated market prices, and (3) variance from actual to expected volume used by customers. Cost of energy includes scheduling coordinator fees for budget purposes only.

Staffing (28.4%) Staffing expenses are under budget due to the timing of new hires.

Professional Services (48.2%) This category includes accounting, IT, technical and other consultants.

Legal Costs (18.5%) This category includes outside legal costs for regulatory and energy procurement needs.

Marketing and customer enrollment (12.1%) Variance is mostly due to the lower than anticipated costs of recent customer enrollments.

Data Management Services (8.5%) These fees non-discretionary and are charged on a per customer basis.

Utility Service Fees (14.0%) These are PG&E and SCE fees charged on a per customer basis.

Other General & Administrative (63.3%) This category includes occupancy costs, industry membership dues, and other general and administrative costs.

Energy and Related Programs (63.9%) Programs expenses have generally been delayed until future periods Budget Commentary for significant items

CENTRAL COAST COMMUNITY ENERGY
October 1, 2024 through December 31, 2024

Return of Investments YTD Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep CASH AND CASH EQUIVALENTSRiver City Bank/ Chase - Money Market and other Interest Earning AccountsFunds Invested - Average Balance 99,664,821$ 114,669,913$ 87,375,820$ Gains/Losses/Interest 1,126,035$ 380,768$ 421,162$ 324,104.99 Average APY 4.58% 4.41% 4.45%INVESTMENTSRBC GAM / Principal Financal/ Schwab/FidelityFunds Invested - Average Balance 125,703,797$ 126,158,519$ 126,652,212$ Gains/Losses/Interest 1,264,066$ 451,482.54 308,267.24 504,316.11 Average APY 4.31% 2.93% 4.78%

CENTRAL COAST COMMUNITY ENERGY
Investment Summary
October 1, 2024 through December 31, 2024

Current 0 - 30 Days 31 - 60 Days 61 - 90 Days > 91 Days A/R Balance 18,466,339$ 12,603,886$ 1,694,390$ 1,208,221$ 6,648,738$ 40,621,574$

CENTRAL COAST COMMUNITY ENERGY
Summary of Accounts Receivable, Net of Bad Debt Allowance As of December 31, 2024

Staff Report Item 6
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Thomas White, Accountant
SUBJECT: Investment Performance Report for the period of October 1, 2023 through September 30, 2024
DATE: March 19, 2025
RECOMMENDATION:

Receive the 3CE investment performance report for the period of October 1, 2023 through September 30, 2024.

BACKGROUND:

The 3CE Audit and Finance Committee (“Committee”) recommended that staff diversify its operating and investment banking partners to mitigate the risk of holding assets in a few concentrated financial institutions. Since the diversification was accomplished, staff has presented the investment performance report to the Committee quarterly and included the reports in the Operations and Policy board meetings.

DISCUSSION/ANALYSIS:
3CE ended the quarter on September 30, 2024, with investment holdings that followed the Investment Policy and the strategy of holding enough cash to meet operating costs, including counterparty collateral calls. The strategy consists of holding three different classes of funds: cash to meet ongoing operating costs, liquidity reserves to meet collateral calls and unforeseen costs, and short-term investments to meet reserves, including the strategic reserve and energy rate stabilization funds. As of September 30, 2024, 3CE held $214.7 million in operating and investment accounts. The table below lists the cash and investment balances by account type.

Cash and Investment Mix Holdings by Institution
Account Type Institution Balance Investment Mix
Operating
River City Bank $79,089,330
Cash (sweep) - $69.8M
money market - $4.3M
cash (operating) - $5.0M
Chase 10,490,963 cash (held for collaterals)
Investment
Schwab 62,047,026 Treasuries - $52.9M
cash (sweep) - $9.1M
Fidelity 63,071,879 Treasuries - $59.8M
money market - $3.3M
Total $214,699,198
The investment strategy is passive, where fixed-income holdings such as Treasury notes and bills are held to maturity, and 3CE receives the coupon income and discount. As of September 30, 2024, 3CE served as investment manager of the $125.1 million held in the Schwab and Fidelity brokerage accounts.

The average annual percentage yield for Treasuries ranged from 4.97% to 5.35% over the fourth quarter.

Treasuries with a maturity date of less than one calendar year accounted for 94.4% of holdings. Two Treasuries with a combined market value of $7.6 million have a maturity date in Q3 of 2026. All investment holdings managed are high-grade rated investments or higher. 3CE’s investment mix aligns with the Investment Policy and California Government Code. As of September 30, 2024, 3CE held $94.5 million in cash and cash equivalents, $121.7 million in U.S.

Treasuries, and $7.5 million in money market funds. Aside from money market funds, all other investment types do not have state investment limits. The State code limits money market funds to 20% of the portfolio. 3CE is well within the State limit at 3.5%.

Cash and Investment Mix Holdings
Type Market Value
% of
Portfolio
Permitted by
CA Government Code
Cash and cash equivalents $94,452,996 44.0% 100%
Money Market Funds 7,524,715 3.5% 20%
U.S. Treasuries 112,721,487 52.5% 100%
Total $214,699,198 100.0%
The FY 2023-24 Adopted Budget, with appropriations of $562.8 million, included estimated investment revenues of $6.4 million. It is estimated that investment earnings from 3CE operating and investment accounts netted $11.7 million, $4.1 million from interest on cash and money market accounts, and $7.5 million from short-term investments, mostly from Treasuries. Interest earned on 3CE collateral held by counterparties is estimated at $1.1 million for total investment and interest earnings of $12.8 million.

The FY 2023-24 Mid-Year Budget Forecast estimated investment income of $10.0 million, 3CE surpassed this estimate due to a favorable interest environment.

FISCAL IMPACT:

There is no fiscal impact to receiving this report.

CONCLUSION:
3CE proactively diversified its financial institutional partners while putting cash and short-term investments to work to take advantage of a continued high-interest environment while retaining cash for ongoing operating costs and collateral calls.

ATTACHMENT(S):

None.

Staff Report Item 7
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Thomas White, Accountant
SUBJECT: Investment Performance Report for the period of October 1, 2024 through December 31, 2024
DATE: March 19, 2025
RECOMMENDATION:

Receive the 3CE investment performance report for the period of October 1, 2024 through December 31, 2024.

BACKGROUND:
3CE Staff, consistent with an Audit and Finance Committee (“Committee”) recommendation, diversified its operating and investment financial partners to mitigate the risk of holding assets in a few concentrated financial institutions. Since the diversification was accomplished, staff has presented the investment performance report to the Committee quarterly and included the reports in the Operations and Policy board meetings.

DISCUSSION/ANALYSIS:
3CE ended the quarter on December 31, 2024, with investment holdings that followed the Investment Policy and the strategy of holding enough cash to meet operating costs, including counterparty collateral calls. The strategy consists of holding three different classes of funds: cash to meet ongoing operating costs, liquidity reserves to meet collateral calls and unforeseen costs, and short-term investments to meet reserves, including the strategic reserve and energy rate stabilization funds. As of December 31, 2024, 3CE held $216.4 million in operating and investment accounts. The table below lists the cash and investment balances by account type.

Cash and Investment Mix Holdings by Institution
Account Type Institution Balance Investment Mix
Operating
River City Bank $79,381,412
Cash (sweep) - $53.7M
money market - $20.4M
cash (operating) - $5.0M
Chase 10,385,434 cash (held for collaterals)
Investment
Schwab 62,694,171 Treasuries - $55.1M
cash (sweep) - $7.6M
Fidelity 63,958,041 Treasuries - $63.8M
money market - $0.1M
Total $216,419,059
The investment strategy is passive, where fixed-income holdings such as Treasury notes and bills are held to maturity, and 3CE receives the coupon income and discount. As of December 31, 2024, 3CE served as investment manager of the $126.7 million held in the Schwab and Fidelity brokerage accounts.

The average annual percentage yield for Treasuries ranged from 3.87% to 5.00% over the first quarter.

Treasuries with a maturity date of less than one calendar year accounted for 94% of holdings. Two Treasuries with a combined market value of $7.6 million have a maturity date in Q3 of 2026. All investment holdings managed are high-grade rated investments or higher. 3CE’s investment mix aligns with the Investment Policy and California Government Code. As of December 31, 2024, 3CE held $77.0 million in cash and cash equivalents, $119.0 million in U.S.

Treasuries, and $20.5 million in money market funds. Aside from money market funds, all other investment types do not have state investment limits. The State code limits money market funds to 20% of the portfolio. 3CE was within the State limit at 9.5%.

Cash and Investment Mix Holdings
Type Market Value
% of
Portfolio
Permitted by
CA Government Code
Cash and cash equivalents $76,992,553 35.5% 100%
Money Market Funds 20,471,967 9.5% 20%
U.S. Treasuries 118,954,538 55.0% 100%
Total $216,419,059 100.0%
The FY 2024-25 Adopted Budget, with appropriations of $730.3 million, included estimated investment revenues of $7.0 million. In the first quarter, investment earnings from operating and investment accounts netted $2.4 million in income, $1.1 million from interest on cash and money market accounts, and $1.3 million from short-term investments.

As of December 31, 2024, 3CE has 111 days of cash on hand. This is based on the total cash, cash equivalents, and investments of $216.4 million, divided by an average daily expense of $1.95 million.

FISCAL IMPACT:

There is no fiscal impact to receiving this report.

CONCLUSION:
3CE proactively diversified its financial institutional partners while putting cash and short-term investments to work to take advantage of a continued high-interest environment while retaining cash for ongoing operating costs and collateral calls.

ATTACHMENT(S):

None.

Staff Report Item 8
TO: 3CE Policy Board of Directors
FROM: Charles McKee, General Counsel
Marina Pantchenko, Deputy General Counsel
PREPARED BY: Marina Pantchenko, Deputy General Counsel
SUBJECT: Adopt Resolution No. PB-2025-01 Establishing a Claims Procedure Pursuant to Government Code Section 935
DATE: March 19, 2025
RECOMMENDATION:

It is recommended that the Policy Board Adopt Resolution No. PB-2025-01 establishing a Claims Procedure pursuant to Government Code Section 935.

BACKGROUND:

California’s Government Code 935 allows public entities to prescribe the process for making monetary or damages claims against the entity that are otherwise exempt from the general claim filing requirements under California Government Code 905. The purpose of this statute is to allow public entities to set a process under which an entity could thoroughly investigate claims, facilitate efficient settlement of meritorious claims, engage in fiscal planning, and avoid liability in the future.

DISCUSSION/ANALYSIS:
3CE’s Joint Exercise of Powers Agreement requires joint approval of the Policy and Operations Boards to initiate or resolve claims and litigation where the Authority is the defendant, plaintiff, petitioner, respondent, cross complainant or cross petitioner, or intervenor. Due to the difficulty in securing joint Policy and Operations Boards meetings quickly, on August 30, 2021, the Policy Board passed Resolution No. PB-2021-06 delegating authority to the Executive Committee to initiate and resolve all claims and litigation. On September 15, 2021, the Operations Board passed Resolution No. OB-2021-03 carrying out the same action.

The proposed Resolution for the Policy Board’s consideration seeks to now build on this delegation of authority and establish a claims process. The Resolution proposed to delegate authority to the Executive Committee to serve as a claims Board, and to authorize the CEO, in consultation with the CFO and General Counsel to settle or compromise a claim up to $50,000 or reject any claim. For the proposed Resolution to go into effect, the Operations Board must pass a similar action.

FISCAL IMPACT: There is no fiscal impact to establishing this procedure.

CONCLUSION: Staff recommends that the Policy Board adopt Resolution No. PB-2025-01 establishing a claims procedure pursuant to Government Code 935.

ATTACHMENT(S):

1. Resolution No. PB-2025-01

RESOLUTION NO. PB-2025-XX

A RESOLUTION OF THE CENTRAL COAST COMMUNITY ENERGY POLICY BOARD OF

DIRECTORS ESTABLISHING A CLAIMS PROCESS PURSUANT TO GOVERNMENT CODE SECTION 935
WHEREAS, Central Coast Community Energy (3CE) is a Joint Powers Authority (JPA) established and operated pursuant to California Government Code sections 6500 et seq. to study, promote, develop, conduct, operate, and manage energy programs in the California Central Coast region of Santa Cruz, Monterey, San Benito, Santa Barbara, and San Luis Obispo Counties; and WHEREAS, the Government Claims Act (Government Code section 900 et seq.) (hereinafter the “Act”) sets forth the general procedure for the presentation of claims as a prerequisite to commencement of actions for money or damages against local public entities; and WHEREAS, the Act excepts certain claims against local public entities from the presentation procedures of the Act; and
WHEREAS, the Act also specifies that local public entities may adopt a procedure for claims excepted under the Act and which are not governed by any other statutes or regulations; and WHEREAS, Section 3.3.5 of 3CE’s JPA Agreement requires: Joint approval of the Policy and Operations Boards shall be required for the initiation or resolution of claims and litigation where the Authority will be the defendant, plaintiff, petitioner, respondent, cross complainant or cross petitioner, or intervenor; provided, however, that the Chief Executive Officer or General Counsel, on behalf of the Authority, may intervene in, become a party to, or file comments with respect to any proceeding pending at the California Public Utilities Commission, the Federal Energy Regulatory Commission, or any other administrative authority, without approval of the Boards as long as such action is consistent with any adopted Board policies; and
WHEREAS, on August 30, 2021 the Policy Board passed Resolution No. PB-2021-06 delegating the authority to the Executive Committee to approve initiation and resolution of all claims and litigation.

The Policy Board also delegated authority to the CEO or General Counsel to approve answering or responding to claims and litigation where 3CE is the defendant or respondent.

WHEREAS, on September 15, 2021, the Operations Board passed Resolution No. PB-2021-03 delegating authority to the Executive Committee to approve initiation and resolution of all claims and litigation. The Operations Board also delegated authority to the CEO or General Counsel to approve answering or responding to claims and litigation where 3CE is the defendant or respondent.

WHEREAS, the Policy Board now desires to adopt a procedure to govern the presentation requirements of those excepted claims to establish a claims procedure pursuant to Government Code 935 and to delegate further authority to the Executive Committee for the review and resolution of the claims, and delegate authority to the CEO, in consultation with the CFO and General Counsel to authorize, settle or compromise any claim up to $50,000.

NOW, THEREFORE, THE CENTRAL COAST COMMUNITY ENERGY POLICY BOARD OF DIRECTORS DOES HEREBY RESOLVE, DETERMINE, AND ORDER AS FOLLOWS:

1. Claims for money or damages. All claims against Central Coast Community Energy, for money or damages, which are excepted by the Act, including under section 905 from Chapter 1 (commencing with Section 900, as amended or renumbered) and Chapter 10 (commencing

with Section 910) of Part 3 within Division 3.6 of Title 1 of the California Government Code and which are not otherwise governed by any other statute or regulation expressly related thereto, shall be governed by the procedure prescribed in this Resolution, in accordance with Government Code section 935, as it may be amended or renumbered.

2. Claim prerequisite to suit. All claims shall be presented as provided in this Resolution and acted upon by Central Coast Community Energy prior to the filing of any legal action on such claims. No such action may be maintained by a person who has not complied with the procedures of this Resolution.

3. Time of presentation. The claim must be presented to the Board Clerk within the time requirements set forth in Government Code section 911.2. For purposes of determining whether a claim is timely presented, a claim is presented to the Board Clerk when it is received at the principal mailing address for the Agency.

4. Form: All claims shall be made in writing and verified by the claimant or by his or her guardian, conservator, executor or administrator. No claims may be filed on behalf of a class of persons unless verified by every member of that class as required by this section. In addition, all claims shall contain the information required by the Government Code section 910. Agency may create a standard claim form for claimant use.

5. Review of claims. Pursuant to Government Code Section 935.2, a Claims Board is hereby established consisting of the Executive Committee and is authorized to perform all functions of the Policy Board regarding claims under this Resolution and the Act. Pursuant to Government Code Section 935.4, the CEO, in consultation with the CFO and General Counsel are authorized to perform all functions of the Policy Board regarding claims under this Resolution and the Act, except the CEO is authorized to allow, compromise, or settle a claim against 3CE up to $50,000 and is authorized to reject any claim. Claims shall be acted upon in accordance with Government Code Sections 912.4, within 45 days after the claim has been presented. If a claim is amended, Agency shall act on the amended within 45 days of when the amended claim is presented. If Agency fails or refuses to act on a claim within the time prescribed by this section, the claim shall be deemed to have been rejected on the last day of the period within which Agency was required to act upon the claim.

Notwithstanding the delegations herein, the Policy Board retains authority to act on all Claims.

6. Notice and effect. This Resolution shall take effect and be in force only once the Operations Board adopts a resolution approving this process.

PASSED AND ADOPTED this 19th Day of March, 2025 by the following vote:

AYES:

NOES:

ABSENT:
__________________________________
Chair, Fred Keeley

Attest:
__________________________________
Board Clerk, Heather Vowell

Staff Report Item 9
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
SUBJECT: CEO Report
DATE: March 19, 2025

STAFFING UPDATE
Zhabiz Ahmadi joined 3CE on January 7, 2025 as a Power Settlement Analyst. Zhabiz brings forth 9 years at the Western Area Power Administration (WAPA), an agency under the Department of Energy. Zhabiz brings extensive experience in power marketing, settlements, metering, and energy accounting. Zhabiz’s background includes analyzing CAISO invoices, allocating and validating charges, and identifying anomalies and issues within the data. Zhabiz is excited to contribute to the team’s success by bringing her diverse skill set and experiences to her new role at 3CE.

Dominic Peters joins us for one year as an Energy Programs Coordinator through the non-profit Climate Corps Fellowship program. Dominic graduated from UC San Diego with a master’s degree in international affairs where he wrote his capstone on the potential impact of renewable meter adapters on solar programs in California. Dominic is passionate about energy policy and has been a part of many impact-driven initiatives, including work as a field data collector for Gridware, where he analyzed potential locations for early-detection wildfire sensors; and as an intern with Diurna Energy, where he researched and prepared briefings on policies related to renewable energy projects on Tribal Lands.

Jessica Swanson joined 3CE on March 10, 2025, as the Principal Management Analyst. Jessica Swanson is a 21+ year U.S. Navy veteran with extensive experience in project management, strategic relationship building, and cross-functional team leadership. She has led and managed complex initiatives in dynamic environments, specializing in government affairs and international program management. Jessica holds a B.S. in Architectural Engineering from Drexel University, an M.A. in National Security Affairs from the Naval Postgraduate School, and a Project Management Professional (PMP) certification.

Ani Ukpe joined 3CE on February 28, 2025, as a Project Manager. Ani holds a Bachelor of Applied Petroleum Engineering Technology and a Petroleum Engineering Technology Diploma from SAIT

Polytechnic in Canada. Ani brings 20 years of experience in project management and engineering. Ani has led a range of projects across industries such as oil and gas, mining, and renewable energy.

Das Williams joined 3CE on January 14, 2025 as a Senior Advisor of Policy and Legislative Affairs.

Das brings over two decades of public service experience to this role, including serving in the California State Assembly and most recently as Santa Barbara County Supervisor and former Chair of 3CE’s Policy Board. Das has demonstrated strong leadership in environmental and energy policy, including his work on landmark legislation like SB350, which set California's path toward 100% clean energy by 2045. His extensive experience in both state and local government, combined with his deep understanding of our Central Coast communities, will help 3CE advance its mission of delivering economic and environmental benefits through clean energy resources.

COMMUNITY ADVISORY COUNCIL REPORT
3CE’s Community Advisory Council (CAC) held its regular meeting on Wednesday, February 5. The Council received a presentation on staff’s findings from community listening sessions held in November 2024 concerning proposed improvements to 3CE’s Electrify Your Home (EYH) program. Attendees of the listening sessions, which were held in Watsonville and Goleta, expressed strong support for the following enhancements:
 Adding additional rebates to the EYH program for induction cooktops  Offering home assessments for customers to evaluate the impact of home electrification on gas and electricity bills
 Expanding eligibility to all licensed contractors
 Piloting a direct installation offering for income-qualified customers A second set of customer workshops have been scheduled for Thursday, April 10 at the Watsonville Civic Plaza Community Room and Thursday, April 17 at the Goleta Valley Community Center.

The Council also received a presentation on the first six months of operations for 3CE’s residential battery rebate program. Interest in the program has been high, with the number of applicants nearly reaching participation projections forecasted for a well-established program. However, applicants have struggled to meet the 50% battery discharge requirement during the peak hours of 4 p.m. to 9 p.m. Of the 123 applicants to the program between July and December 2024, only 26, or 21%, were able to meet the discharge requirements and receive a rebate. In response, staff has worked to develop a web-based scheduling assistant which allows customers, in one click, to set their batteries to meet program requirements. (Customers can also customize the days and hours of their discharge through the assistant.) Staff are reaching out individually to the remaining 97 applicants to help them comply with the program criteria and receive their rebate. Initial reaction to scheduling assistance has been overwhelmingly positive. Also, during the program’s first six months, staff expanded eligibility criteria to include leased home battery systems to increase participation from income-qualified customers.

Finally, the CAC received a draft evaluation report on 3CE’s Energy Programs’ performance for fiscal year 2023-24. Highlights from the report include:
 During FY 2023-24, 3CE distributed $11 million in rebates and incentives – a 12% increase from the previous year.
 Across all 11 of the agency’s programs, 36% of funding was distributed to income-qualified customers and underserved communities.
 3,758 metric tons of CO2 was avoided because of the FY 2023-24 Energy Programs implementation, equivalent to taking 968 gas-powered vehicles off the road.

Staff gathered input on the evaluation and will present a final version of the report at the next regularly scheduled CAC meeting, which will be held on Wednesday, May 7 at 4:00 p.m.

EV CHARGER ASSET PILOT UPDATE
3CE’s EV Charger Asset Pilot is testing ways to help increase access to both workplace and public charging stations. For workplace charging, 3CE has begun installation of level 2 chargers at its new office in San Luis Obispo. This project is currently in the construction phase with anticipated completion in May 2025. As part of this pilot project, 3CE was awarded a $68,400 grant from the SLO Air Pollution Control District (APCD).

For the EV Charger Asset Pilot’s public facing chargers, 3CE is currently working with City of Santa Maria to install level 2 and level 3 chargers at South McCellan Street, across from the public library. This project is in the preliminary planning phase with the construction phase anticipated to begin in Q2 2025. As part of this pilot project, 3CE was awarded a $200,000 grant from the Santa Barbara APCD.

POWER SUPPLY UPDATE
3CE anticipates issuing a new Request for Proposals (RFP) on March 19 to secure offers for new clean, renewable, and reliability projects. 3CE has nearly 70% of its demand covered by twenty-one long-term renewable and energy storage agreements, with seven online projects and the remainder still under development. This RFP will allow for the consideration and selection of additional cost-effective projects to meet regulatory requirements and move 3CE closer to its goal of serving 100% of our retail demand with clean and renewable resources. Bids will be due in April, with selections and contract negotiations to begin in late May or early June.

CALIFORNIA PUBLIC UTILITIES COMMISSION ACTION ON GENERAL ORDER 167 On March 13, the California Public Utilities Commission (CPUC) is expected to approve amendments to General Order (GO) 167 to include Energy Storage System (ESS) facilities. ESS facilities of 50 MW or greater will be subject to all GO 167 requirements. These facilities are now required to maintain a control operator log with a chronological history of the facility, retaining log entries for 5 years. Each operator must record a Facility Status Entry daily, noting any outages, abnormal conditions, or status updates. Facilities must

file a Maintenance Plan and Certification within 180 days of GO-167-C’s adoption and update it every two years. Similarly, an Operation Plan and Certification must be filed within 180 days of adoption for active ESS facilities, with updates every two years. ESS owners must report safety-related incidents within 24 hours and provide relevant information to the CPUC’s Safety and Enforcement Division upon request.

Finally, ESS owners must comply with the CAISO outage coordination protocol.

ATTACHMENT(S):

1. Customer Outreach and Engagement Report

Customer Outreach and
Engagement Report
Statistics and Activity
Central Coast Community Energy
Communications and Outreach Department
February 27, 2025

2 Table of Contents
Member Agency Engagement.................................................................................................... 3 Member Agency Quarterly Meeting ........................................................................................ 3 Monthly Enrollment Meetings ................................................................................................. 3 Reach Code Initiatives............................................................................................................ 3 CalCCA Benchmarking Workshop .......................................................................................... 3 3CE Enrollment.......................................................................................................................... 4 Engagement:.......................................................................................................................... 4 Customer Retention and Opt-Outs ......................................................................................... 4 Customer Opt-Outs ................................................................................................................ 5 Reasons for Opting Out (11/1/24-2/26/2025): ......................................................................... 6 Summary of Customer Retention and Opt-Outs to Date ......................................................... 6 3CE Enrollment.......................................................................................................................... 7 Media Outreach ......................................................................................................................... 8 Facebook ............................................................................................................................... 8 Facebook En Espanol ............................................................................................................ 8 Instagram ............................................................................................................................... 8 Twitter (X)............................................................................................................................... 9 LinkedIn.................................................................................................................................. 9 Earned Media......................................................................................................................... 9

3 Member Agency Engagement
Member Agency Quarterly Meeting
City and county staff from member agencies were invited to participate in one of two sessions to review updates and stay informed about key issues in the transition to renewable energy on the Central Coast. Despite receiving registrations from thirty people representing thirteen agencies, severe weather in the region impacted attendance, with eighteen participants ultimately joining the calls.

Monthly Enrollment Meetings
In January, residents and businesses in the County of San Luis Obispo and the City of Atascadero were successfully enrolled on their meter read dates. 3CE continued regular coordination with staff from enrolling communities through monthly check-in meetings, content sharing, and ongoing information exchanges. Close collaboration between 3CE and city and county staff has been essential to ensuring a smooth enrollment process.

Reach Code Initiatives
3CE staff participated in a Reach Code workshop with the City of Goleta and County of Santa Barbara, promoting a regional approach to building electrification reach codes. Separately, 3CE continues to support City of Goleta in developing its New Construction Reach Code.

CalCCA Benchmarking Workshop
Staff from CCAs across California met to share best practices for Member Agency/Key Account outreach and account management. During the session, 3CE presented its 3Cprime Marketing Kit as a resource for effective engagement.

4 3CE Enrollment
Atascadero and Unincorporated San Luis Obispo County
Engagement:
 Three of the four enrollment mailers for customers in the City of Atascadero and unincorporated San Luis Obispo County were delivered to USPS mailboxes and email inboxes beginning Saturday, November 2. The fourth and final notification is scheduled for distribution during the first week of March.
 Staff has conducted monthly meetings with representatives from the City of Atascadero and the County of San Luis Obispo to provide updates on the enrollment process.  Additionally, staff has engaged with large commercial accounts and community groups in the enrollment areas to address questions and promote available rebate programs.  On February 18, 3CE hosted a reception at the Atascadero City Hall Council Chambers, where representatives from the City and 3CE discussed the benefits of community choice aggregation for both customers and the broader community.

Customer Retention and Opt-Outs (11/1/24-2/26/24):
3CE’s goal for enrollment in the City of Atascadero and unincorporated San Luis Obispo County is to retain 90% of eligible load.

In Atascadero, 14,051 customers are eligible for 3CE service. 1,281 customers opted out, including 1,180 residential customers and 100 commercial customers. The opt outs represent

8.9% of eligible accounts, meaning that 91.1% of customers elected to stay with 3CE. The current enrolled eligible load is 91.6%.

In unincorporated San Luis Obispo County, 60,842 customers are eligible for 3CE service. 3,465 customers opted out, including 3,101 residential accounts, 232 commercial, and 132 agricultural accounts. The opt-outs represent 5.7% of eligible accounts, meaning that 94.3% of customers elected to stay with 3CE. The current enrolled eligible load is 97.5%.

Below is a breakdown of opt-outs in the City of Atascadero and Unincorporated San Luis Obispo County following 3CE’s third enrollment notification mailer. Opt-outs coinciding with customer notifications about automatic enrollment are expected as part of the Community Choice Aggregation model of automatic enrollment. Staff expects to effectively retain 90-94% of customers in the enrolled areas.

5 Customer Opt-Outs (11/1/24-02/26/2025):

Atascadero # of
Accounts
%

CARE/FERA
% Medical Baseline
Residential - Total 1180 12% 8%
Residential – Non-NEM 688 18% 8%
Residential - NEM 492 4% 10%
Commercial - Total 100 0% 0%
Commercial – Non-NEM 98 0% 0%
Commercial - NEM 2 0% 0%
Total Opt-Outs (Atascadero) 1280
Unincorporated SLO County # of
Accounts
%

CARE/FERA
% Medical Baseline
Residential - Total 3101 10% 5%
Residential – Non-NEM 1866 4% 8%
Residential - NEM 1235 18% 9%
Commercial - Total 232 0% 0%
Commercial – Non-NEM 200 0% 0%
Commercial - NEM 32 0% 0%
Agriculture - Total 132 0% 0%
Agriculture – Non-NEM 117 0% 0%
Agriculture - NEM 15 0% 0%
Other – Total 4 0% 0%
Other – Non-NEM 4 0% 0%
Other 0 0% 0%
Total Opt-Outs (SLO County) 3469

6 Reasons for Opting Out (11/1/24-2/26/2025):

Summary of Customer Retention and Opt-Outs to Date
3CE’s goal for enrollment in the City of Atascadero and unincorporated San Luis Obispo County is to retain 90% eligible load.
 In Atascadero, opt-outs to date represent 8.9 % of eligible accounts, with 91.1% of customers electing to stay with 3CE and retaining 91.6% of eligible load.  In unincorporated San Luis Obispo County, opt-outs to date represent 5.7% of eligible accounts, with 94.3% of customers electing to stay with 3CE and retaining 97.5% of eligible load.

Consistent with past enrollments, 3CE’s customer service center received higher than average call volume following the enrollment mailers. Most customers who elected to opt-out did so because they disliked being automatically enrolled.

Overall, this data indicates that 3CE is on track to meet its goal of retaining 90% of eligible load in both the City of Atascadero and unincorporated San Luis Obispo County. 0 500 1000 1500 2000
CONCERNS ABOUT GOVERNMENT-RUN …

DECLINE TO PROVIDE
DISLIKE BEING AUTOMATICALLY …
HAVE RENEWABLE ENERGY RELIABILITY …
OTHER

RATE OR COST CONCERNS

SERVICE OR BILLING CONCERNS

OPT OUT BY REASON GIVEN

ATASCADERO INC UNINC SAN LUIS OBISPO CO

7 3CE Enrollment
as of February 17, 2025
Member Community % of Eligible Accounts % of Eligible Load** ARROYO GRANDE 94.36% 92.64%
ATASCADERO 91.10% 91.66%
BUELLTON 96.64% 94.87%
CAPITOLA 96.02% 97.92%
CARMEL 97.57% 97.96%
CARPINTERIA* 95.04% 95.59%
DEL REY OAKS 95.26% 96.86%
GOLETA* 94.42% 94.56%
GONZALES 86.98% 96.73%
GREENFIELD 87.25% 95.53%
GROVER BEACH 96.25% 95.77%
GUADALUPE 97.47% 99.35%
HOLLISTER 88.56% 93.06%
MARINA 93.74% 92.26%
MONTEREY 95.88% 94.56%
MORRO BAY 97.16% 95.42%
PACIFIC GROVE 96.65% 97.28%
PASO ROBLES 90.86% 88.72%
PISMO BEACH 95.39% 96.57%
SALINAS 89.21% 92.72%
SAN JUAN BAUTISTA 91.71% 92.97%
SAN LUIS OBISPO 96.44% 96.95%
SAND CITY 95.98% 98.76%
SANTA CRUZ 96.67% 97.71%
SANTA MARIA 97.63% 95.31%
SCOTTS VALLEY 96.40% 97.61%
SEASIDE 94.01% 96.10%
SOLEDAD 87.63% 94.16%
SOLVANG 96.32% 96.08%
MONTEREY CO 92.44% 95.16%
SAN BENITO CO 90.03% 95.40%
SAN LUIS OBISPO CO 93.26% 97.50%
SANTA BARBARA CO* 93.89% 97.46%
SANTA CRUZ CO 94.83% 94.83%
WATSONVILLE 90.52% 93.34%
Total 93.45% 91.68%
*SCE Numbers are not current

8 **Load data is still being refined in our data system. Slight adjustments in load reporting may be reflected in reports produced over the next 90 days.

Media Outreach
Facebook
 Followers: 1.76K
 Page Reach: 340K
 Page Impressions: 506K
 Post Reach: 1,249
 New page followers: 14
 Top Performing Content: 💡Real Stories, Real Impact in 3CE Communities!💡 🌟 Meet Rosemary Soto: A Voice for the Community 🎥 As a child of farmworkers, Rosemary Soto grew up with a deep appreciation for the earth and a commitment to community. Now, as a dedicated organizer and member of 3CE’s Community Advisory Council, she’s bringing that passion to life. 💡 In this heartfelt video, Rosemary shares her mission to serve and how 3CE is delivering impactful programs directly to community members—meeting them where they are. 🌱⚡ Join us in celebrating leaders like Rosemary who make a difference every day. Watch her story now! #CommunityLeadership #CleanEnergy #EmpoweringCommunities #CentralCoast #City of Atascadero #CountyofSLO Facebook En Espanol
 Followers: 171
 Page Reach: 52
 Page Impressions: 72
Instagram
 Followers: 1.21K
 New Followers: 21
 Reach: 58K
 Top Performing Content: 💡Real Stories, Real Impact in 3CE Communities!💡 🌟 Meet Rosemary Soto: A Voice for the Community 🎥 As a child of farmworkers, Rosemary Soto grew up with a deep appreciation for the earth and a commitment to community. Now, as a dedicated organizer and member of 3CE’s

9 Community Advisory Council, she’s bringing that passion to life. 💡 In this heartfelt video, Rosemary shares her mission to serve and how 3CE is delivering impactful programs directly to community members—meeting them where they are. 🌱⚡ Join us in celebrating leaders like Rosemary who make a difference every day. Watch her story now! #CommunityLeadership #CleanEnergy #EmpoweringCommunities #CentralCoast #City of Atascadero #CountyofSLO

Twitter (X)
 Followers: 1.1K
 New Followers: -2
 Top Performing Content: Exciting News for Atascadero & SLO County! By the end of January, nearly all new customers will be enrolled with 3CE, receiving clean, renewable energy! Together, we’re reducing emissions & building a greener future. #CleanEnergy #3CE #SustainableFuture
LinkedIn
 Followers: 2.8K
 New Followers: 102
 Post Clicks: 456
 Top Performing Content: 🌟 Exciting News from 3CE! 🌟
We are thrilled to announce that Sophia Schwirzke has begun a new position as Community Relations Manager! 🎉
Sophia brings a wealth of experience, passion, and dedication to this role, and her leadership will undoubtedly enhance our ability to connect with and support our community. This is fantastic news not just for our team but also for the customers and stakeholders we serve every day.

Please join us in congratulating Sophia on attaining this well-deserved position! 👏👏👏
hashtag#Team3CE hashtag#CommunityRelations hashtag#Leadership hashtag#Sustainability hashtag#Congratulations
Earned Media
 Coastal View News: Morning Rotary learns about renewable energy with Das Williams | News | coastalview.com
 Santa Barbara Independent: Celebrate Opening of 17 Electric Vehicle Chargers at Goleta City Hall THIS Thursday, January 23 - The Santa Barbara Independent

10  KKFX-TV: County Supervisor Das Williams will take on a new role at Central Coast Community Energy: Kinetiq Player
 KEYT-TV: County Supervisor Das Williams will take on a new role at Central Coast Community Energy: Kinetiq Player
 Santa Barbara Independent: Former State Legislator and Santa Barbara County Supervisor Das Williams Joins Central Coast Community Energy as Senior Advisor of Policy and Legislative Affairs - The Santa Barbara Independent  Energy NewsData: Robert Shaw was elected chair of the California Community Choice Association’s board of directors: Quick Bites: Energy News Roundup for Jan. 21, 2025 | News in Brief | newsdata.com
 Antelope Valley Press: Rosamond energy site gets loan from feds | News | avpress.com
 Noozhawk: Das Williams Starts Work at Central Coast Community Energy | Local News | Noozhawk
 Lookout Santa Cruz: Watsonville Community Hospital appoints Alexandra Friel to board, Allyson Violante as government and community relations director - Lookout Santa Cruz
 Noozhawk: Green Ribbon Means Go for Goleta City Hall EV Chargers | Local News | Noozhawk
 Canary Media: Massive underground air-battery project lands $1.76B… | Canary Media
 Yahoo! News/SLO Tribune: Central Coast Community Energy now serves all of SLO County. Here’s why that’s good news | Opinion
 Utility Dive: Hydrostor gets $1.76B DOE conditional loan guarantee for 4 GWh energy storage project | Utility Dive
 Energy Storage News: DOE offers US$1.76 billion to Hydrostor for A-CAES project - Energy-Storage.News
 E&E News: DOE floats $1.76B loan for California grid storage project - E&E News by POLITICO
 California City News: Capitola Mayor Steps Down to Lead United Way of Santa Cruz | California City News

Staff Report Item 10
TO: 3CE Policy Board of Directors
FROM: Jerri Strickland, Manager of Energy Policy
SUBJECT: Receive a presentation on the Power Charge Indifference Adjustment and provide staff direction
DATE: March 19, 2025
RECOMMENDATION:

Receive a presentation on the Power Charge Indifference Adjustment (PCIA) and provide direction to staff.

BACKGROUND:

Initially conceived in 2001, the PCIA was designed to prevent cost shifts between Investor-Owned Utility (IOU) customers and Direct Access (DA) customers.1 With the growth of CCAs across the state since 2010, it also now applies to customers who depart IOU service for a CCA electric generation provider.

California Public Utilities Code Section 365.1 mandates that utilities not be penalized for the departure of customers to other providers (unbundled customers) and calls upon the California Public Utilities Commission (CPUC) to establish a mechanism to ensure that the customers remaining with Investor Owned Utilities (IOUs) for generation service (bundled customers) remain indifferent to such departures.2 The PCIA is the CPUC’s response to this mandate, and is designed to ensure that customers who switch to a CCA or DA provider do not unfairly benefit by leaving bundled customers with a disproportionate share of the stranded costs resulting from their departure. The charge seeks to ensure that customers who leave IOUs for alternative generation providers still contribute to the costs of power procurement and other obligations previously incurred by the utility on their behalf. Importantly, both bundled and unbundled customers pay a portion of the stranded costs associated with the PCIA.

1 Decision (D.) 02-11-022
2 California Code, Public Utilities Code - PUC § 365.1

The PCIA and its implementation has been a subject of ongoing debate, with various revisions and regulatory actions occurring in 2018, 2019, and 2021 CPUC Decisions.3 Critics have argued that the PCIA is too high and unfairly burdens unbundled customers, preventing them from benefiting fully from the more localized and often lower-cost energy procurement strategies of their new energy providers. Others claim that the PCIA is not high enough and puts a cost shift onto bundled customers. There have been ongoing regulatory proceedings to reform the PCIA, with discussions focusing on how to fairly allocate costs among customers and whether changes to the methodology for calculating the adjustment are needed. These debates involve balancing the needs of IOU customers with those of CCA and DA customers and addressing concerns over fairness and transparency in the way stranded costs are allocated.

Annually, the PCIA is set through the Energy Resources Recovery Account (ERRA) Forecast Proceeding, which determines IOU generation rates for the next calendar year. Applications filed by the IOUs are submitted every May, with Commission decisions scheduled for December and resulting rate changes effective January 1.

The ERRA proceedings concern IOU accounting and portfolio management and are not intended as a forum to consider policy changes. However, because of the drastic increase in energy prices for Resource Adequacy (RA), which caused the PCIA to go negative for the first time and resulted in a credit to unbundled customers, the CPUC considered policy changes to the PCIA methodology as part of its 2024 ERRA forecast proceeding. 4 Some of the proposals considered by the CPUC included how various RA resources are valued – including impacts of the new 24-hour Slice of Day RA Paradigm and using a market price cap instead of actual market prices for certain attributes. Following the ERRA proceeding, the CPUC opened a new Rulemaking (R. 25-02-005) to further consider and evaluate both near- and long-term PCIA modifications and reforms. 5 DISCUSSION/ANALYSIS:

3 D.18-10-019; D19-10-011; D.21-05-030
4 A.24-05-009; A.24-05-007
5 R. 25-02-005

The methodology for PCIA calculation directly affects the competitive differential between IOUs and Community Choice Aggregation entities, such as 3CE. 3CE’s generation rate reflects its cost to serve customers, including operations, portfolio construction, and risk management – factors within the agency’s control. On the other hand, the PCIA, which is applied to 3CE customers’ bills, reflects IOU legacy costs and is set by the CPUC. A high PCIA reduces CCA competitiveness, and a low or negative PCIA enhances CCA’s competitive position.

The amount collected by the PCIA is the difference between the IOU’s Total Portfolio Costs (TPC) and their current portfolio’s market value. TPC is determined by the cost of Power Purchase Agreements (PPAs) and Utility-Owned Generation (UOG) costs, minus revenue from IOU sales of Resource Adequacy (RA) and Renewable Portfolio Standards (RPS) attributes. The portfolio’s current market value is calculated by applying a Market Price Benchmark (MPB) value to the IOU’s generation resources.

Overview of how PCIA is value is calculated:

The MPB is based on a model, specifically the Platts-ICE Forward Curve, which predicts electricity market prices for the upcoming year. The MPB for RPS, on the other hand, is derived from actual IOU transactions for bundled renewable energy credits (RECs). The Energy Index reflects the estimated market value of each unit of energy in a utility portfolio in dollars per megawatt-hour ($/MWh). The RPS Adder represents the incremental value of each unit of RPS-eligible energy due to its eligibility, also in $/MWh.

The RA MPB is a bit more complex in that it has three subcomponents, reflecting each type of RA product required for compliance with the RA program: System, Local, and Flexible.6 The RA MPB reflects the estimated value of each unit of capacity in a utility portfolio that can be used to satisfy Resource Adequacy obligations.

When System, Local and Flexible vary in cost, the categorization of resources can cause large swings in the PCIA.

The complexity of the PCIA is increased by its inconsistent application across traditional customer class distinctions (residential, commercial, and agricultural), with each IOU having its own PCIA classes. Additionally, the year a customer departs IOU service further affects the PCIA.

6 D.19-10-001

The CPUC’s current PCIA Rulemaking proceeding will focus on modifications to the MPB calculations, aiming for a May 2025 decision to be incorporated into the 2026 ERRA forecasts. Proposed changes include adjustments to the transaction data used for MPB calculations, the possibility of monthly or seasonal MPBs instead of annual values and the consolidation of calculations for Local, Flexible, and System RA into a single MPB. A second track of the proceeding will explore broader, long-term improvements to the ERRA and PCIA processes, including IOU rate forecasts and methods to mitigate rate volatility.

FISCAL IMPACT:

There is no financial impact by receiving this report.

CONCLUSION:

The PCIA is a volatile rate component influenced by market prices outside of 3CE's and other Load-Serving Entities’ control. This is crucial because it affects 3CE’s competitiveness when compared to SCE and PG&E. The volatility of the PCIA creates the need for strategies to achieve long-term rate-stability and insulate customers from unexpected rate fluctuations.

ATTACHMENT(S):

None.

Staff Report Item 11
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Juan Lopez, Director of Finance
SUBJECT: Receive a presentation on 3CE’s FY 2023-24 audited financial statements DATE: March 19, 2025
RECOMMENDATION:

Receive a presentation on 3CE’s FY 2023-24 audited financial statements.

BACKGROUND:
3CE is responsible for the preparation and fair presentation of financial statements. The independent auditor performs tests to ensure the financial statements are free from material misstatement. 3CE worked diligently with its accounting vendor and external auditors over the past few months to ensure a proper review of financial controls and financial statements. The Audit and Finance Committee received the audited financial statements at its February 27, 2025 special meeting.

The FY 2023-24 financial statements consist of the following:
• Independent Auditors’ Report
• Management’s Discussion and Analysis
• Financial statements, including:
 Statements of Net Position
 Revenues and Expenses and Changes in Net Position
 Statements of Cash Flows
 Notes to the Financial Statements
DISCUSSION/ANALYSIS:

The Independent Auditors’ Report (Report) affirms that 3CE’s financial statements fairly present, in all material respects, the organization’s financial position as of September 30, 2023, and 2024, along with the respective changes in financial position and cash flows. The report includes an unqualified, or

"clean," audit opinion, indicating that the financial statements are free from material misstatements and comply with applicable accounting standards.

The report confirms that the auditors did not identify any internal control deficiencies classified as material weaknesses. Representatives from Kosmatka Donnelly & Co. LLP, the external auditors, will attend the Audit and Finance Committee meeting to provide insights and address any questions regarding their review.

FY 2023-24 Financial Highlights
 The net position decreased by $23.7 million, down from a $34.7 million increase in the prior year. Cash, cash equivalents, and short-term investments decreased by $28.5 million over the prior year.
 Operating revenues grew over $92.8 million from the prior year, driven primarily by the rate adjustments that occurred on October 1, 2023 and January 1, 2024 to reflect the increased cost of energy.
 Growth in non-operating revenues resulting from higher interest income from a favorable rate environment and engaged investment management, resulting in $3.3 million in higher investment revenue than the prior year.
 The cost of energy increased by approximately $148.5 million due to rising energy attribute costs, with $122.4 million for Resource Adequacy (RA) and $55.3 million in Renewable Energy Certificates (RECs) offset by lower energy generation costs of $19.3 million.  Non-energy operating costs increased $6.0 million from the prior year, mainly from increased costs for higher participation in energy programs, personnel due to increased FTEs from the prior year, data manager fees, and increased community outreach.  Total assets decreased by $0.6 million from the prior year from an increase in accounts receivable, accrued revenue from increases in retail electricity rates, deposits held by counterparties for collateral, and capital assets from the purchase of the San Luis Obispo office building, offset by lower cash and cash equivalents.
 Liabilities increased by $23.2 million from the prior year primarily due to higher accrued cost of electricity, accounts payable, and funds held for executed Treasury trades, offset by a drop in deposits held for development security deposits.

FY 2023-24 Actuals Versus Budget
On May 29, 2024, the Audit and Finance Committee received the FY 2023-24 Mid-Year Budget Forecast.

The Forecast estimated expenditures of $574.1 million, 2% over the $562.8 million adopted budget. The increase in expenditures resulted from higher RA costs, partially offset by lower non-energy operating costs. The Forecast projected a $12.7 million decrease in net position by the end of the fiscal year.

However, actual results showed expenditures reaching $581.4 million, with revenues totaling $557.4 million, leading to a larger-than-anticipated operating shortfall of $24.0 million.

FY 2023-24 Actuals Versus Budget Highlights
Revenue vs. Budget
 Total revenue of $557.4 million reached 99% of the budget, $5.5 million short of the $562.8 million budget.
 Operating revenue from net electricity sales was $12.1 million below budget, primarily due to lower-than-expected retail volume, offset by reduced uncollectible accounts.  Non-operating income of $13.0 million exceeded budget by $6.6 million, driven by favorable interest rates and active investment management.

Expenditures vs. Budget
 Total expenditures of $581.4 million exceeded the budget by 3%, coming in $18.5 million above the $562.8 million budget.
 Cost of energy of $548.8 million was higher than budget by $28.5 million, a 5% variance. The increase is mainly attributed to a $15.1 million higher-than-budgeted cost for RECs to meet Renewables Portfolio Standard (RPS) compliance for the 2021-2024 multi-year compliance period.

Of the $15.1 million, $6.0 million were for RECs allocated for the two last months of Fiscal Year 2022-23 that were not recorded in that year due to the timing of the contract execution and invoicing. RA compliance costs exceed the budget by $13.4 million.  Non-energy operating costs of $32.5 million were 23% under budget due to lower spending on energy programs, unspent contingencies, contracted services, and personnel vacancies.

CONCLUSION:

As of September 30, 2024, 3CE’s net position decreased by $23.7 million, primarily due to higher-than-forecasted costs for energy attributes. Like other load-serving entities, 3CE faced delays in Power Purchase Agreements (PPAs) due to interconnection issues, supply chain disruptions, rising project costs, and contract negotiations. These challenges led to a less robust renewable energy portfolio, requiring increased market REC purchases. Additionally, regulatory changes further tightened RA supply by restricting the RA value of renewables, introducing delivery requirements for imported RA, and increasing supply obligations.

FISCAL IMPACT:

There is no financial impact by receiving this report.

ATTACHMENT(S):

1. FY 2023-24 Audited Financial Statements

2. FY 2023-24 Supplemental Budgetary Schedule, Investment Summary, and Dashboard

FINANCIAL

STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023

INCLUDING REPORT OF INDEPENDENT AUDITORS

CENTRAL COAST COMMUNITY ENERGY
YEARS ENDED SEPTEMBER 30, 2024 AND 2023

TABLE OF CONTENTS
Independent Auditor’s Report ………………………………………………………................ 1 Management’s Discussion and Analysis ……………………………………………................ 4 Basic Financial Statements:

Statements of Net Position ……………………………………………………………. 10
Statements of Revenues, Expenses and Changes in Net Position ……………………. 11 Statements of Cash Flows …………………………………………………………….. 12
Notes to the Basic Financial Statements ……………………………………................ 14

Pisenti & Brinker LLP has joined practices with Kosmatka, Donnelly & Co., LLP (dba, KDP Certified Public Accountants, LLP). The former Pisenti & Brinker LLP Partners are now Partners of KDP Certified Public Accountants, LLP (KDP). KDP Certified Public accountants, LLP is a licensed CPA firm that provides attest services to its clients. Pisenti & Brinker Management LLC provides professional tax and business consulting services to its clients. Pisenti & Brinker Management, LLC and KDP Certified Public Accountants, LLP practice as an alternative practice structure in accordance with the AICPA Code of Professional Conduct and applicable laws, regulations, and professional standards. 3562 Round Barn Circle, Suite 200
Santa Rosa, CA 95403
(707) 542-3343  Office
(707) 527-5608  Fax
Independent Auditor’s Report
To the Board of Directors
Central Coast Community Energy
Opinion
We have audited the accompanying financial statements of Central Coast Community Energy (3CE), which comprise the statements of net position as of September 30, 2024 and 2023, the related statements of revenue, expenses and changes in net position, and cash flows for the years then ended, and the related notes to the financial statements.

In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of 3CE as of September 30, 2024 and 2023, and the results of its operations and cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Basis for Opinion
We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of 3CE and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Responsibilities of Management for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about 3CE’s ability to continue as a going concern within one year after the date that the financial statements are issued or available to be issued, including any currently known information that may raise substantial doubt shortly thereafter.

Independent Auditor’s Report (continued)
Auditor’s Responsibilities for the Audits of the Financial Statements Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS will always detect a material misstatement when it exists.

The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the financial statements.

In performing an audit in accordance with GAAS, we:
• Exercise professional judgment and maintain professional skepticism throughout the audits. • Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements.
• Obtain an understanding of internal control relevant to the audits in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of 3CE’s internal control. Accordingly, no such opinion is expressed. • Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the financial statements.
• Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about 3CE’s ability to continue as a going concern for a reasonable period of time.

We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audits, significant audit findings, and certain internal control-related matters that we identified during the audits.

Required Supplementary Information
Accounting principles generally accepted in the United States of America require that management’s discussion and analysis be presented to supplement the basic financial statements. Such information is the responsibility of management and, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

Kosmatka, Donnelly & Co., LLP
Santa Rosa, California
February 12, 2025

CENTRAL COAST COMMUNITY ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
4 The purpose of management’s discussion and analysis (MD&A) is to help stakeholders and other readers understand what the financial statements and notes in this report say about Central Coast Community Energy’s (3CE) financial health and why it has changed since last year. It contains information drawn from other parts of the report, accompanied by explanations informed by the finance staff’s knowledge of 3CE’s finances.

Overview of the Financial Statements
3CE’s financial report contains basic financial statements, which include:
o The Statements of Net Position include all of 3CE’s assets, liabilities, and net position and provides information about the nature and amount of resources and obligations at a specific point in time.
o The Statements of Revenues, Expenses, and Changes in Net Position report all of 3CE’s revenue and expenses for the years shown.
o The Statements of Cash Flows report the cash provided and used by operating activities, as well as other sources and uses, such as capital and investing activities. o The notes to the Basic Financial Statements provide additional details and information related to the basic financial statements.

CENTRAL COAST COMMUNITY ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
5 Financial Summary
3CE’s Net Position
2024 2023 2022
Current assets $ 314,501,404 $ 324,238,888 $ 259,993,090 Noncurrent assets
Capital assets, net 3,817,033 2,008,218 219,319
Other noncurrent assets 8,916,927 1,543,979 1,731,180
Total noncurrent assets 12,733,960 3,552,197 1,950,499
Total assets 327,235,364 327,791,085 261,943,589
Current liabilities 97,925,104 54,996,528 45,601,781
Noncurrent liabilities 11,144,817 30,923,232 9,131,250
Total liabilities 109,069,921 85,919,760 54,733,031
Net position
Net investment in capital assets 2,650,082 520,678 219,319 Unrestricted 215,515,361 241,350,647 206,991,239
Total net position $ 218,165,443 $ 241,871,325 $ 207,210,558 As of September 30, 2024, 3CE’s total net position was approximately $218,000,000, a decrease of $24,000,000 as compared to September 30, 2023.
3CE’s Change in Net Position
2024 2023 2022
Operating revenues $ 544,456,634 $ 451,619,272 $ 401,698,835 Nonoperating revenues 12,893,661 9,635,091 3,800,219
Total income 557,350,295 461,254,363 405,499,054
Operating expenses 580,996,244 426,540,098 388,276,955
Nonoperating expenses 59,933 53,498 -
Total expenses 581,056,177 426,593,596 388,276,955
Change in net position (23,705,882) $ $ 34,660,767 $ 17,222,099 Electricity sales increased in 2024 as a result of price increases. Despite the increase in revenues, there was a decrease in net position in 2024 due to significant increases in the cost of electricity incurred by 3CE which were driven by market price increases for renewable energy and regulatory resource adequacy.

CENTRAL COAST COMMUNITY ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
6 Detailed Analysis
Current assets decreased from $324,000,000 at the end of fiscal year 2023 to $315,000,000 at the end of fiscal year 2024. The decrease was primarily due to cash outflows to cover increasing energy costs. Current assets at the end of fiscal year 2024 were primarily comprised of cash and investments of $219,000,000, accounts receivable of $44,000,000, and accrued revenue of $31,000,000.

Capital assets are reported net of depreciation and amortization. Each year, the change is mostly due to capital asset acquisitions less depreciation and amortization expense. Capital assets include construction in progress, land, software, leasehold improvements, furniture, equipment, a vehicle, building and a leased asset. The increase from 2023 to 2024 was primarily the result of an office building purchased during the current year in the City of San Luis Obispo.

Other noncurrent assets consist of the long-term portion ($1,330,000) of a $2,000,000 loan made in 2022 to the County of Santa Cruz to acquire electric generation equipment.

The largest component of current liabilities is the cost of electricity delivered to customers that was not paid by 3CE at the end of the fiscal year. Current liabilities for the cost of energy increased each year due to changes in payment terms of certain energy products, as well as the prices of those products. Accrued cost of electricity was approximately $77,000,000 and $49,000,000 at the end of fiscal years 2024 and 2023, respectively. The primary driver of the increased cost of electricity was market price increases for renewable energy and resource adequacy resulting from constrained supply.

Noncurrent liabilities consist of supplier security deposits and the long-term portion of lease liability related to 3CE’s office premises. The reduction in noncurrent liabilities was a result of repayment of security deposits to suppliers that had been held by 3CE.

Operating revenues increased each year from fiscal years 2022 to 2024, primarily from increases in rates charged to customers. 3CE also receives revenues from sources other than retail customer sales. These sources include liquidated damage revenue resulting from electricity suppliers’ noncompliance with contract provisions and grant income used to assist with various customer programs.

CENTRAL COAST COMMUNITY ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
7 Detailed Analysis (continued)
Grant income from the California Arrearage Payment Plan (CAPP) was included in nonoperating revenues for fiscal years 2022 and 2023. This grant was applicable for two years and did not recur in fiscal year 2024. Investment income increased each year due to changes in market interest rates as well as increases in invested assets.

Operating expenses increased each year primarily due to market forces that resulted in increases in the cost of electricity, 3CE’s largest expense. 3CE procures energy from a variety of sources to reduce market risk and to maintain a balanced renewable power portfolio. The primary driver of the increase in energy costs from 2023 to 2024 was the rising costs in the resource adequacy market and the timing of certain contracts that were executed to comply with the State’s Renewable Portfolio Standards (RPS) through its acquisition of Renewable Energy Certificates (RECs).

Significant Capital Asset and Long-Term Financing Activity Capital assets include office equipment, such as computers, furniture, a vehicle, leasehold improvements and a leased asset for 3CE’s office premises. Additionally, during fiscal year 2024, 3CE purchased real estate to be used for future office operations in the San Luis Obispo region.

Assets that are leased by 3CE, such as office premises, are recorded in the Statement of Net Position with a related liability for future obligations.

CENTRAL COAST COMMUNITY ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
8 Currently Known Facts, Decisions, or Conditions
The fiscal year ended September 30, 2024 was a year of stable operations and growing cost pressures from increased costs of energy (COE), resource adequacy (RA) compliance and environmental attributes. Total revenue of $557.3 million is estimated at 99.0% of budget. Total expenditures of $581.1 million were over budget, representing a 3.3% variance. RA compliance and meeting Renewable Portfolio Standard (RPS) requirements for Compliance Period 4 contributed to higher COE. Like other load-serving entities (LSEs), 3CE faced delays in long-term PPAs caused by interconnection issues, supply chain disruptions, rising project costs, and contractual negotiations.

Infrastructure supply development remains constrained. These constraints are driven by the increased demand for renewable and other energy resources by urban electrification and the growth in technology data centers and associated artificial intelligence processing needs. 3CE views interconnection delays to existing or planned new build clean and renewable projects as the largest risk. The average wait time for projects entering the interconnection queue has increased to 5-8 years before becoming operational, whereas in the past, it took 2-3 years. Furthermore, a recent report indicated only 15% of projects within the California Independent System Operator (CAISO) queue were successful at coming online. CAISO, in coordination with the CPUC and CEC, has been endeavoring to reform the interconnection process, 3CE has a deep understanding of this challenging environment and will adjust business strategies as necessary to succeed. 3CE holds a portfolio of contracts that mitigate exposure to price spikes in the CAISO markets.

However, in the past fiscal year, CAISO market prices, as well as electricity futures prices in liquid forward markets, declined, leading to cost pressures for counterparty suppliers. At the same time, the overall market for electricity and related commodity products is experiencing a rising price environment. The rising price environment is driven by elevated costs to enter into long-term offtake agreements such as power purchase agreements (PPAs) and energy storage offtake agreements, elevated prices for RA, and environmental attributes such as Renewable Energy Certificates (RECs).

While the forward prices for energy indicate higher-than-normal wholesale prices for the foreseeable future, with every new fixed-price PPA project to come online, 3CE limits its exposure to these spot market prices.
3CE is working towards a 100% clean and renewable energy portfolio and is currently negotiating several agreements to add generation and energy storage to move closer to that goal. While the targeted timeline for achieving this goal is 2030, 3CE may choose to extend it to a later date, if interconnection wait times do not improve or customer affordability becomes a concern. 3CE has also taken steps to mitigate the elevated prices for RA. 3CE’s RA procurement strategy seeks long-term fixed-price contracts for RA that will help reduce our exposure to the spot market RA prices.

Beginning in 2026, 3CE has long-term contracts with two hybrid natural gas resources paired with energy storage that will provide valuable dispatchable energy and an RA benefit at fixed prices.

CENTRAL COAST COMMUNITY ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
9 Currently Known Facts, Decisions, or Conditions (continued) 3CE is regularly reviewing its Energy Risk Management Policy (ERMP) to ensure it continues to meet 3CE’s business needs while maintaining sufficient risk tolerances. Purchases made at fixed contractual prices reduce the need to purchase energy in the volatile daily open market. Fixed price energy purchases provide for suppliers to deliver to 3CE at a fixed price. They are used to manage the electricity commodity price risk that 3CE faces as an LSE. Specific to 3CE’s customers, fixed price energy hedges are used to provide cost certainty and rate stability. The target hedge percentages depend on time and the hedge pricing relative to historical energy costs. In general, 3CE targets hedging 63-110% of its exposure in energy products on a short-duration basis of under a year. 3CE continues to comply with its ERMP and regularly updates its Energy Risk Committee on hedging.
3CE is participating in a joint procurement effort with CC Power (California Community Power), a joint action agency made up of member CCAs, to explore the possibility of entering into a build-transfer agreement. Currently, in its early stages, CC Power is soliciting developer bids for build-transfer projects and evaluating offers. If CC Power identifies a potential project, 3CE would have the option to participate in a portion of the project, the remainder of which would be shared by other CC Power members who opted to participate in the project. 3CE retains a strong customer and revenue base with low opt-out levels. 3CE will start serving the City of Atascadero and the County of San Luis Obispo beginning January 1, 2025. These two enrollments will add around 70,000 customer accounts, bringing the total customer count to about 515,000. 3CE continues prioritizing community outreach and communication efforts to ensure a strong local presence, establishing 3CE as the preferred renewable energy provider. 3CE serves approximately 94% of all eligible customers in the service area and that rate of participation is expected to remain stable.
3CE continues to actively engage in legislative and regulatory matters that can impact its energy procurement requirements and energy-related expenditures.

Requests for Information
This financial report is designed to provide 3CE’s board members, stakeholders, customers, and creditors with a general overview of 3CE’s finances and to demonstrate 3CE’s accountability for the funds under its stewardship.

Please address any questions about this report or requests for additional financial information to the finance department at 70 Garden Court, Suite 300, Monterey, CA 93940.

BASIC FINANCIAL STATEMENTS

CENTRAL COAST COMMUNITY ENERGY
The accompanying notes are an integral part of these financial statements. 10

STATEMENTS OF NET POSITION
SEPTEMBER 30, 2024 AND 2023
2024 2023
ASSETS
Current assets
Cash and cash equivalents $ 150,539,681 $ 196,033,869
Accounts receivable, net of allowance 44,437,895 32,759,275 Accrued revenue 30,948,530 24,865,108
Other receivables 6,363,531 4,273,462
Investments 68,632,549 59,245,668
Prepaid expenses 1,829,224 380,211
Deposits 11,559,276 6,494,094
Loan receivable 190,718 187,201
Total current assets 314,501,404 324,238,888
Noncurrent assets
Investments 7,563,666 -
Deposits 23,182 23,182
Loan receivable 1,330,079 1,520,797
Capital assets, net of depreciation and amortization 3,817,033 2,008,218 Total noncurrent assets 12,733,960 3,552,197
Total assets 327,235,364 327,791,085

LIABILITIES
Current liabilities
Accrued cost of electricity 76,773,246 48,922,476
Accounts payable 4,864,146 2,777,101
Due to broker 12,035,076 -
Other accrued liabilities 800,930 741,801
User taxes and energy surcharges due to other governments 1,977,148 1,753,727 Security deposits - energy suppliers 1,149,299 501,000
Lease liability 325,259 300,423
Total current liabilities 97,925,104 54,996,528
Noncurrent liabilities
Security deposits - energy suppliers 10,303,125 29,756,280 Lease liability 841,692 1,166,952
Total noncurrent liabilities 11,144,817 30,923,232
Total liabilities 109,069,921 85,919,760

NET POSITION
Net investment in capital assets 2,650,082 520,678
Unrestricted 215,515,361 241,350,647
Total net position $ 218,165,443 $ 241,871,325

CENTRAL COAST COMMUNITY ENERGY
The accompanying notes are an integral part of these financial statements. 11

STATEMENTS OF REVENUES, EXPENSES

AND CHANGES IN NET POSITION
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
2024 2023

OPERATING REVENUES
Electricity sales, net $ 544,358,419 $ 450,713,404
Liquidated damages - 750,000
Other income 98,215 155,868
Total operating revenues 544,456,634 451,619,272

OPERATING EXPENSES
Cost of electricity 547,248,240 398,746,769
Contract services 13,387,839 10,820,099
Staff compensation 7,830,528 6,200,592
Other operating expenses 1,695,758 1,869,295
Program incentives 10,248,121 8,484,775
Depreciation and amortization 585,758 418,568
Total operating expenses 580,996,244 426,540,098
Operating income (loss) (36,539,610) 25,079,174

NONOPERATING REVENUES (EXPENSES)
Investment income 12,893,661 8,184,122
Grant revenue 1,450,969 -
Interest and financing costs (59,933) (53,498)
Nonoperating revenues (expenses) 12,833,728 9,581,593
CHANGE IN NET POSITION (23,705,882) 34,660,767
Net position at beginning of year 241,871,325 207,210,558 Net position at end of year $ 218,165,443 $ 241,871,325

CENTRAL COAST COMMUNITY ENERGY
The accompanying notes are an integral part of these financial statements. 12

STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
2024 2023

CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from customers $ 536,022,766 $ 466,288,740
Other operating receipts 23,814,719 1,052,868
Receipts of deposits and collateral 49,873,965 53,684,900 Payments to suppliers for electricity (550,573,743) (392,088,215) Payments of deposits and collateral (69,256,483) (30,759,035) Payments for other goods and services (15,088,564) (12,022,290) Payments for program incentives (8,250,194) (7,797,967) Payments of staff compensation (7,654,438) (6,467,227)
Payments of taxes and energy surcharges to other governments (9,199,968) (8,274,859) Net cash provided (used) by operating activities (50,311,940) 63,616,915

CASH FLOWS FROM NONCAPITAL FINANCING ACTIVITIES
Grant revenue 1,450,969 -

CASH FLOWS FROM CAPITAL AND RELATED

FINANCING ACTIVITIES
Payments of lease liability (360,354) (264,318)
Payments to acquire capital assets (2,413,580) (509,105) Net cash used by capital and related financing activities (2,773,934) (773,423)

CASH FLOWS FROM INVESTING ACTIVITIES
Investment income received 10,981,615 7,060,790
Proceeds from investment sales 127,312,461 111,223,174
Principal payments received of loan receivable 187,201 292,002 Purchase of investments (130,889,591) (137,227,427)
Net cash provided (used) by investing activities 7,591,686 (18,651,461) Net change in cash and cash equivalents (45,494,188) 45,643,000 Cash and cash equivalents at beginning of year 196,033,869 150,390,869 Cash and cash equivalents at end of year $ 150,539,681 $ 196,033,869

CENTRAL COAST COMMUNITY ENERGY
The accompanying notes are an integral part of these financial statements. 13

STATEMENTS OF CASH FLOWS (CONTINUED)
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
2024 2023
Operating income (loss) $ (36,539,610) $ 25,079,174
Adjustments to reconcile operating income (loss) to net cash provided (used) by operating activities
Depreciation and amortization expense 585,758 418,568
(Increase) decrease in:

Accounts receivable, net of allowance (11,678,620) 14,348,325 Accrued revenue (6,083,425) (6,703,164)
Other receivables (1,775,892) (1,913,221)
Prepaid expenses (1,449,013) (71,792)
Deposits (4,805,654) 1,799,836
Increase (decrease) in:

Accrued cost of electricity 27,850,770 8,847,894
Accounts payable 2,106,052 1,167,725
Other accrued liabilities 59,129 (294,223)
User taxes and energy surcharges due to other governments 223,421 (188,237) Security deposits - energy suppliers (18,804,856) 21,126,030 Net cash provided (used) by operating activities $ (50,311,940) $ 63,616,915 Acquisition of lease asset $ 1,678,196 - $
Unrealized appreciation and timing differences in investment income 1,912,046 $ $ 1,123,332

NONCASH INVESTING ACTIVITES

RECONCILIATION OF OPERATING INCOME (LOSS) TO NET

CASH PROVIDED (USED) BY OPERATING ACTIVITIES

NONCASH CAPITAL AND RELATED FINANCING ACTIVITES

CENTRAL COAST COMMUNITY ENERGY

NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
14 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

REPORTING ENTITY
Central Coast Community Energy (3CE) is a Joint Powers Authority created on February 21, 2017, and its jurisdictions consist of the following local governments as of September 30, 2024:

Counties Cities and Towns
Monterey Arroyo Grande Morro Bay
San Benito Atascadero Pacific Grove
San Luis Obispo Buellton Paso Robles
Santa Barbara Capitola Pismo Beach
Santa Cruz Carmel-by-the-Sea Salinas
Carpinteria San Juan Bautista
Del Rey Oaks San Luis Obispo
Goleta Sand City
Gonzales Santa Cruz
Greenfield Santa Maria
Grover Beach Scotts Valley
Guadalupe Seaside
Hollister Soledad
Marina Solvang
Monterey Watsonville
3CE is separate from and derives no financial support from its members. 3CE is governed by two Governing Boards, a Policy Board and an Operations Board. Each Board is comprised of 19 members with 19 alternates representing the participating communities. Some of the 19 members represent more than one jurisdiction. Policy Board Members are elected officials from 3CE member communities. Operations Board Members are executives leading the member cities and counties. 3CE was formed to acquire retail electricity for the residents and businesses within its members’ jurisdictions, study, promote, conduct, operate, and manage energy and energy-related climate change programs, and to exercise all other powers necessary and incidental to accomplishing these objectives. A core function of 3CE is to provide electric service that includes the use of renewable sources under the Community Choice Aggregation Program under California Public Utilities Code (CPUC) Section 366.2.
3CE began its energy delivery operations in March 2018. Electricity is acquired from commercial suppliers and delivered through existing physical infrastructure and equipment managed by Pacific Gas and Electric Company (PG&E) and Southern California Edison (SCE).

CENTRAL COAST COMMUNITY ENERGY

NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
15 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

BASIS OF ACCOUNTING
3CE’s financial statements are prepared in accordance with Generally Accepted Accounting Principles (GAAP). The Governmental Accounting Standards Board (GASB) is responsible for establishing GAAP for state and local governments through its pronouncements. 3CE’s operations are accounted for as a governmental enterprise fund and are reported using the economic resources measurement focus and the accrual basis of accounting, similar to business enterprises. Accordingly, revenues are recognized when they are earned; and expenses are recognized at the time liabilities are incurred. Enterprise fund type operating statements present increases (revenues) and decreases (expenses) in total net position. Reported net position is segregated into three categories: Net investment in capital assets, restricted, and unrestricted.

When both restricted and unrestricted resources are available for use, it is 3CE’s policy to use restricted resources first, and then unrestricted resources as they are needed.

CASH AND CASH EQUIVALENTS
For purposes of the Statements of Cash Flows, 3CE defines cash and cash equivalents to include cash on hand, demand deposits and short-term investments with an original maturity of three months or less.

INVESTMENTS
Investments are stated at fair value based on prices listed on a national exchange for debt securities.

Certificates of deposits are stated at cost. 3CE intends to hold its securities to maturity. Investments with a maturity of less than one year are shown as current assets in the Statement of Net Position.

Investments with a maturity of one year or more are shown as noncurrent assets in the Statement of Net Position.
3CE’s Investment Policy permits the following types of investments:

U.S. Treasury obligations
Obligations of the State of California
Obligations of any local agency within California
Registered treasury notes or bonds of the other 49 states Commercial paper
Repurchase agreements
Local Agency Investment Fund (State Pool)
County Investment Fund (County Pool)

CENTRAL COAST COMMUNITY ENERGY

NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
16 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

PREPAID EXPENSES
Payments made to vendors that will benefit periods beyond the end of the current fiscal year are recorded as prepaid expenses.

DEPOSITS
Contracts to purchase energy may require 3CE to provide the supplier with advanced payments or security deposits. Deposits are generally held for the term of the contract and are classified as current or noncurrent assets depending on the length of time the deposits will be outstanding.

LEASE ASSET AND LEASE LIABILITY
3CE recognizes an asset and liability when it enters into certain leasing arrangements. The cost of the leased asset is amortized over the term of the lease. The lease liability is the present value of payments expected to be paid to the lessor during the lease term. 3CE’s only leased asset and liability relate to its office premises.

CAPITAL ASSETS AND DEPRECIATION
3CE’s policy is to capitalize furniture and equipment valued over $1,000 that is expected to be in service for over one year. Depreciation is computed according to the straight-line method over estimated useful lives of three years for electronic equipment, seven years for furniture, and six years for leasehold improvements. Buildings and improvements are depreciated over 30 years. 3CE does not own any electric generation, transmission or distribution assets.

DUE TO BROKER
Investments purchased before the end of the fiscal year, but settled after the fiscal year, are recorded as due to broker.

SECURITY DEPOSITS-ENERGY SUPPLIERS
Various energy purchase contracts entered into by 3CE require the supplier to provide 3CE with a security deposit. These deposits are generally held for the term of the contract or until the completion of certain benchmarks. Deposits are classified as current or noncurrent depending on the length of time the deposits will be held.

CENTRAL COAST COMMUNITY ENERGY

NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
17 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

NET POSITION
Net position is presented in the following components:

Net investment in capital assets: This component of net position consists of capital assets, net of accumulated depreciation and amortization, and reduced by outstanding borrowings that are attributable to the acquisition, construction, or improvement of those assets.

Unrestricted: This component of net position consists of net position that does not meet the definition of “net investment in capital assets”.

OPERATING AND NONOPERATING REVENUES
Operating revenues include energy sales to retail and wholesale customers, and liquidated damages from suppliers that fail to meet delivery commitments.

Investment income includes interest earned on bank deposits as well as unrealized gains and losses on its investment holdings. Interest and investment income are considered nonoperating revenues.

REVENUE RECOGNITION
3CE recognizes revenue according to the accrual basis. This includes invoices issued to customers during the reporting period and electricity estimated to have been delivered, but not yet billed at year-end. Management estimates that a portion of the billed amounts will be uncollectible. Accordingly, an allowance for uncollectible accounts has been recorded. Revenue is presented net of estimated uncollectible amounts.

OPERATING AND NONOPERATING EXPENSES
Operating expenses include the costs of electricity, contractor services, staffing, other operating expenses, program incentives, and depreciation and amortization of capital assets. Expenses not meeting this definition are reported as nonoperating expenses.

COST OF ELECTRICITY
During the normal course of business, 3CE purchases electrical power from numerous suppliers.

Electricity costs include the cost of energy and capacity arising from contracts with energy suppliers and generation credits, and load and other charges arising from 3CE’s participation in the California Independent System Operator’s (CAISO) centralized market. The cost of electricity and capacity is recognized as “Cost of Electricity” in the Statements of Revenues, Expenses and Changes in Net Position.

CENTRAL COAST COMMUNITY ENERGY

NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
18 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

ELECTRICAL POWER PURCHASED (CONTINUED)
To comply with the State of California’s Renewable Portfolio Standards (RPS), 3CE acquires RPS eligible renewable energy evidenced by Renewable Energy Certificates (Certificates) recognized by the Western Renewable Energy Generation Information System. 3CE obtains Certificates with the intent to retire them and does not sell or build surpluses of Certificates with a profit motive. An expense is recognized at the point that the cost of the Certificate is due and payable to the supplier. 3CE purchases capacity commitments from qualifying electricity generators to comply with the CPUC’s Resource Adequacy Program. The goals of the Resource Adequacy Program are to provide sufficient resources to the CAISO to ensure the safe and reliable operation of the electricity grid in real-time and to provide appropriate incentives for the siting and construction of new resources needed for reliability in the future.

STAFFING COSTS
3CE pays employees bi-weekly and fully pays its obligation for health benefits and contributions to its defined contribution retirement plan each month. 3CE is not obligated to provide post-employment healthcare or other fringe benefits, and accordingly, no related liability is recorded in these financial statements. 3CE provides compensated time off, and the related liability is recorded in these financial statements.

ESTIMATES
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect certain reported amounts and disclosures. Accordingly, actual results could differ from those estimates.

RECLASSIFICATIONS
Certain amounts in the prior-year financial statements have been reclassified for comparative purposes to conform to the presentation of the current-year financial statements. These reclassifications did not result in any change in the previously reported net position or change in net position.

CENTRAL COAST COMMUNITY ENERGY

NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
19 2. CASH AND CASH EQUIVALENTS
3CE maintains its cash in both interest-bearing and non-interest-bearing deposit accounts in several banks. 3CE’s deposits are subject to California Government Code Section 16521, which requires banks to collateralize public funds in excess of the Federal Deposit Insurance Corporation (FDIC) limit of $250,000 by 110%. Certain short-term investments with original maturities of less than three months are classified as cash and cash equivalents, which are not subject to the collateral requirement or FDIC coverage previously mentioned. Accordingly, the amount of risk is not disclosed. 3CE monitors its risk exposure on an ongoing basis.

3. RECEIVABLES AND DEPOSITS

ACCOUNTS RECEIVABLE
Accounts receivable was as follows as of September 30:
2024 2023
Accounts receivable from customers $ 54,437,895 $ 43,313,058 Allowance for uncollectible accounts (10,000,000) (10,553,783) Net accounts receivable $ 44,437,895 $ 32,759,275
The majority of account collections occur within the first few months following customer invoicing. 3CE estimates that a portion of the invoiced accounts will not be collected. 3CE continues collection efforts on accounts in excess of de minimis balances regardless of the age of the account. Although collection success generally decreases with the age of the receivable, 3CE continues to have success in collecting older accounts. The allowance for uncollectible accounts at the end of a period includes reserves for amounts invoiced during the current and prior fiscal years. During 2024 and 2023, 3CE recorded $7,233,000 and $6,864,000, respectively, as an increase to the allowance in anticipation of uncollectible accounts. Amounts estimated to be uncollectible are reported as a reduction in electricity sales in the Statement of Revenues, Expenses and Changes in Net Position. Other changes in the allowance for uncollectible accounts from year-to-year are the result of account write-offs.

OTHER RECEIVABLES
Other receivables consist primarily of amounts due from energy suppliers, generally as a result of certain wholesale transactions for energy products.

DEPOSITS
Combined current and noncurrent deposits were approximately $11,582,000 and $6,517,000 as of September 30, 2024 and 2023, respectively. The majority of current deposits relate to collateral posted with the CAISO, which is determined based on 3CE’s market exposure at a given time and funds provided to an energy program implementer to issue customer incentive payments.

CENTRAL COAST COMMUNITY ENERGY

NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
20 4. INVESTMENTS
During the years ended September 30, 2024 and 2023, 3CE purchased investments with original maturities of three months or more. As of September 30, investments, presented at fair value, were as follows:
2024 2023
Current Investments:

U.S. Treasury Securities $ 68,632,549 $ 45,545,580
Commercial paper 3,700,088 -
Certificate of deposits 10,000,000 -
Total current investments $ 68,632,549 $ 59,245,668
2024 2023
Noncurrent Investments:

U.S. Treasury Securities $ 7,563,666 $ -

FAIR VALUE MEASUREMENT
GASB Statement No. 72, Fair Value Measurement and Application, sets forth the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. Level 1 inputs are quoted prices in active markets for identical assets, Level 2 inputs are significant other observable inputs, and Level 3 inputs are significant unobservable inputs.

In instances where inputs used to measure fair value fall into different levels in the above fair value hierarchy, fair value measurements in their entirety are categorized based on the lowest level input that is significant to the valuation. 3CE’s assessment of the significance of particular inputs to these fair value measurements requires judgment and considers factors specific to each asset or liability.

As of September 30, 2024 and 2023, 3CE’s investments are considered Level 1 inputs, except for certificates of deposits, which are based on the nominal value which is materially consistent with fair value. Quoted prices in active markets were used for determining fair value measurement.

CENTRAL COAST COMMUNITY ENERGY

NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
21 4. INVESTMENTS (continued)

CREDIT RISK
Credit risk is the risk an issuer or other counterparty to an investment will not fulfill its obligations.

Certain investments, such as obligations of the U.S. government or obligations explicitly guaranteed by the U.S. government, are not considered to have credit risk. Credit risk information for other investments is not available.
3CE’s investment policy addresses this risk. 3CE limits investments to those allowed by Section 53600 of the California Government Code that addresses the risk allowable for each investment.

CUSTODIAL CREDIT RISK – CERTIFICATE OF DEPOSITS
Custodial credit risk is the risk that in the event of a financial institution failure, 3CE’s deposits may not be returned to 3CE. 3CE’s deposits are subject to California Government Code Section 16521, which requires banks to collateralize public funds in excess of the Federal Deposit Insurance Corporation (FDIC) limit of $250,000 by 110%.

As of September 30, 2024 and 2023, none of 3CE’s bank balances are known to be individually exposed to custodial credit risk.

CUSTODIAL CREDIT RISK - INVESTMENTS
Custodial credit risk for investments is the risk that, in the event of the failure of the counterparty to a transaction, 3CE would not be able to recover the value of the investment or collateral securities that are in the possession of an outside party. All of 3CE’s investments are exposed to custodial credit risk.
3CE’s investment policy addresses custodial credit risk. All investments owned by 3CE shall be held in safekeeping by a third-party custodian, acting as an agent for 3CE under the terms of a custody agreement.

CENTRAL COAST COMMUNITY ENERGY

NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
22 4. INVESTMENTS (continued)

INTEREST RATE RISK - INVESTMENTS
Interest rate risk is the risk that changes in interest rates will adversely affect the fair value of an investment. Duration is a measure of the price sensitivity of a fixed income portfolio to changes in interest rates. It is calculated as the weighted average time to receive a bond’s coupon and principal payments. The longer the duration of a portfolio, the greater its price sensitivity to changes in interest rates. 3CE manages its exposure to declines in fair values by limiting the weighted average maturity of its investments. 3CE intends to hold investments to maturity.

Following is a summary of investment maturities as of September 30, 2024:

Investment Maturities
Investment Type Fair Value Less Than 1 Year 1-5 Years
U.S. Treasury Securities $ 76,196,215 $ 68,632,549 $ 7,563,666 All investments had a maturity of less than one year as of September 30, 2023.

5. CAPITAL ASSETS
Capital asset activity for the year ended September 30, 2024 was as follows:

Beginning
balance Increases
Ending
balance
Capital assets not being depreciated:

Building - construction in progress $ - $ 74,068 $ 74,068 Land - 898,658 898,658
Capital assets being depreciated and amortized:

Furniture and equipment 696,716 13,873 710,589
Leasehold improvements 90,661 90,661 -
Software 400,126 400,126 -
Building 1,407,974 - 1,407,974
Lease asset 1,678,196 1,678,196 -
Total capital assets being depreciated and amortized 2,865,699 1,421,847 4,287,546 Less accumulated depreciation and amortization:

Furniture, equipment and leasehold improvements (539,063) (116,743) (655,806) Software (66,688) (133,376) (200,064)
Lease asset (251,730) (335,639) (587,369)
Total accumulated depreciation and amortization (857,481) (585,758) (1,443,239) Total capital assets, net of depreciation and amortization 2,008,218 $ $ 1,808,815 $ 3,817,033

CENTRAL COAST COMMUNITY ENERGY

NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
23 5. CAPITAL ASSETS (continued)
Capital asset activity for the year ended September 30, 2023 was as follows:

Beginning
balance Increases
Ending
balance
Capital assets being depreciated and amortized:

Furniture and equipment $ 599,545 $ 97,171 $ 696,716
Leasehold improvements 58,687 31,974 90,661
Software 400,126 - 400,126
Lease asset 1,678,196 - 1,678,196
Total capital assets being depreciated and amortized 658,232 2,207,467 2,865,699 Less accumulated depreciation and amortization:

Furniture, equipment and leasehold improvements (438,913) (100,150) (539,063) Software (66,688) - (66,688)
Lease asset (251,730) - (251,730)
Total accumulated depreciation and amortization (438,913) (418,568) (857,481) Total capital assets, net of depreciation and amortization 219,319 $ $ 1,788,899 $ 2,008,218

6. LEASE
A lease asset is reported in accordance with GASB No. 87.

On October 27, 2022, 3CE entered into a 3-year non-cancelable lease for its office premises for a term commencing on January 1, 2023. The lease agreement includes an option to renew the lease for two additional one-year terms.

Rental payments under this lease were $360,000 and $330,000 for the years ended September 30, 2024 and 2023, respectively.

As of September 30, 2024, future minimum lease payments under this lease were projected as follows:

Principal Interest Total
Year ending September 30,
2025 $ 325,259 $ 45,905 $ 371,164
2026 351,568 30,731 382,299
2027 379,426 14,342 393,768
2028 110,698 878 111,576
Total $ 1,166,951 $ 91,856 $ 1,258,807

CENTRAL COAST COMMUNITY ENERGY

NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
24 7. GRANT REVENUE
3CE administered a grant from the California Arrearage Payment Program (CAPP) that offers financial assistance for California energy utility customers to help reduce past due energy account balances that increased during the COVID-19 pandemic. This program concluded in 2023.

8. DEFINED CONTRIBUTION RETIREMENT PLAN
3CE provides retirement benefits to eligible employees through a 401(a) Retirement Plan (Plan). The Plan is a defined contribution (Internal Revenue Code 401(a)) retirement plan established to provide benefits at retirement to employees of certain qualified employers admitted by the Plan. The Plan is administered by the Public Agency Retirement System (PARS). The number of Plan participants was 41 and 34 as of September 30, 2024 and 2023, respectively. 3CE is required to contribute 10% of covered payroll as a match to required employee contributions. 3CE contributed approximately $591,000 and $502,000 for the years ended September 30, 2024 and 2023, respectively. Plan provisions and contribution requirements as they apply to 3CE are established and may be amended by the Governing Board. 3CE elected out of the Social Security system for employees eligible for the Plan. 3CE also provides a 457(b) Retirement Plan where employees can make tax deferred contributions.

9. RISK MANAGEMENT
3CE is exposed to various risks of loss related to torts; theft of, damage to, and destruction of assets; and errors and omissions. During the year, 3CE purchased insurance policies from investment-grade commercial carriers to mitigate risks that include those associated with earthquakes, theft, general liability, errors and omissions, and property damage. 3CE has general liability coverage of $1,000,000, with a deductible of $1,000.
3CE maintains risk management policies, procedures and systems that help mitigate credit, liquidity, market, operating, regulatory and other risks that arise from participation in the California energy market.

Credit guidelines include a preference for transacting with investment-grade counterparties, evaluating counterparties’ financial condition and assigning credit limits as applicable. These credit limits are established based on risk and return considerations under terms customarily available in the industry. In addition, 3CE enters into netting arrangements whenever possible and, where appropriate, obtains collateral and other performance assurances from counterparties.

25 CENTRAL COAST COMMUNITY ENERGY

NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023

10. PURCHASE COMMITMENTS

POWER AND ELECTRIC CAPACITY
In the ordinary course of business, 3CE enters into power purchase agreements to acquire energy and electric capacity. The price and volume of purchased power is largely fixed. Variable priced power, which is a small part of 3CE’s portfolio, is generally linked to the market price of either natural gas or power at the date of delivery. Variable volume is generally associated with contracts to purchase energy from resources with varying availability and production, such as solar, wind and hydroelectric facilities.
3CE enters into long-term power purchase agreements to ensure stable competitive rates for its customers and to comply with state law and voluntary targets for renewable and greenhouse gas (GHG) free products.

The following table represents the expected, undiscounted, contractual obligations outstanding as of September 30, 2024:

Year ending September 30,
2025 554,000,000$
2026 329,000,000
2027 265,000,000
2028 248,000,000
2029 270,000,000
2030-2053 3,299,000,000
Total $ 4,965,000,000

26 CENTRAL COAST COMMUNITY ENERGY

NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023

11. JOINT VENTURE
3CE participates in a joint powers agreement (JPA) through the California Community Choice Financing Authority (CCCFA). CCCFA was formed as to assist its members by undertaking the financing or refinancing of energy prepayments through tax-advantaged bonds on behalf of one or more of the members by, among other things, issuing or incurring bonds and entering into related contracts with its members. Any debt or liability incurred by CCCFA on behalf of a member to prepay for renewable energy is not a debt or liability of that member. Furthermore, the assets of CCCFA in the form of prepaid energy or reserves held by the respective bond trustees for any prepayment transaction undertaken on behalf of a member does not constitute an asset or reserve of that member.

CCCFA issued the following bonds, excluding original issue premium, which are to be used to finance energy purchases that will be delivered to 3CE. No debt, liability, or obligation of CCCFA is a debt, liability, obligation of 3CE.

Deal Date issued Amount
2023F December 2023 647,750,000 $
3CE will purchase energy from CCCFA in the same manner as it purchases energy from other suppliers. 3CE purchased approximately $22,579,000 and $0 from CCCFA during fiscal years 2024 and 2023, respectively. The outstanding purchase commitments related to these financing facilities of $463,011,000 are included in Note 10. This amount represents executed energy contracts assigned to CCCFA at September 30, 2024. Additional contracts will be assigned throughout the full bond period.

Each member of CCCFA is responsible for paying an equal portion of CCCFA’s general and administrative operating costs as determined by its board. During the years ended September 30, 2024, and 2023, 3CE contributed approximately $30,000 and $18,000, respectively, to CCCFA to assist in its operating activities.

The financial statements of CCCFA are available online at http://www.cccfa.org/key-documents.html.

12. FUTURE GASB PRONOUNCEMENTS
The requirements of the following GASB Statements are effective for years ending after September 30, 2024:

GASB has approved GASB Statement No. 102, Certain Risk Disclosures, GASB Statement No. 103, Financial Reporting Model Improvements, and GASB Statement No. 104, Disclosure of Certain Capital Assets.

Management is evaluating the effect of implementation of these statements.

FY 2023-24 Supplemental Budgetary
Schedule, Investment Summary, and
Dashboard

1 ACCOUNTANTS’ COMPILATION REPORT

Board of Directors
Central Coast Community Energy
Management is responsible for the accompanying special purpose statements of Central Coast Community Energy (a California Joint Powers Authority) which comprise the budgetary comparison schedule for the periods ended September 30, 2024, and for determining that the budgetary basis of accounting is an acceptable financial reporting framework. We have performed a compilation engagement in accordance with Statements on Standards for Accounting and Review Services promulgated by the Accounting and Review Services Committee of the AICPA. We did not audit or review the accompanying statement nor were we required to perform any procedures to verify the accuracy or completeness of the information provided by management. Accordingly, we do not express an opinion, a conclusion, nor provide any assurance on this special purpose budgetary comparison statement.

The special purpose statement is prepared in accordance with the budgetary basis of accounting, which is a basis of accounting other than accounting principles generally accepted in the United States of America. This report is intended for the information of the Board of Directors of the Authority.

Management has elected to omit substantially all of the note disclosures required by accounting principles generally accepted in the United States of America in these interim financial statements.

Central Coast Community Energy’s annual audited financial statements include the note disclosures omitted from these interim statements. If the omitted disclosures were included in these financial statements, they might influence the user’s conclusions about the Authority’s financial position, results of operations, and cash flows. Accordingly, these financial statements are not designed for those who are not informed about such matters.

We are not independent with respect to the Authority because we performed certain accounting services that impaired our independence.

Maher Accountancy
1101 Fifth Avenue, Suite 200 San Rafael, CA 94901 415 459 1249 mahercpa.com San Rafael, CA
November 26, 2024

Actual Budget Amount % Actual Budget Amount % Budget
Annual Budget
Less Actual
YTD

REVENUES AND OTHER SOURCES
Electricity sales $ 49,442,948 $ 51,386,828 $ (1,943,880) -4% $ 543,806,598 $ 563,933,447 $ (20,126,849) 96% $ 563,933,447 $ 20,126,849 Uncollectible accounts 7,126,858 (625,000) 7,751,858 -1240% 551,821 (7,500,000) 8,051,821 -7% (7,500,000) (8,051,821) Electricity sales, net 56,569,806 50,761,828 5,807,978 11% 544,358,419 556,433,447 (12,075,028) 98% 556,433,447 12,075,028 Investment and miscellaneous income 2,231,492 533,000 1,698,492 319% 12,991,876 6,400,000 6,591,876 203% 6,400,000 (6,591,876) Total revenues and other sources 58,801,298 51,294,828 7,506,470 15% 557,350,295 562,833,447 (5,483,152) 99% 562,833,447 5,483,152 EXPENDITURES AND OTHER USESCurrent Expenditures Cost of energy 94,239,267 77,293,336 (16,945,931) -22% 548,776,152 520,297,514 (28,478,638) 105% 520,297,514 (28,478,638) Salaries and benefits 769,615 794,756 25,141 3% 7,830,528 9,537,076 1,706,548 82% 9,537,076 1,706,548 Services and supplies 4,476,913 2,749,908 (1,727,005) -63% 24,749,921 32,998,857 8,248,936 75% 32,998,857 8,248,936 Total current expenditures 99,485,795 80,838,000 (18,647,795) -23% 581,356,601 562,833,447 (18,523,154) 103% 562,833,447 (18,523,154) Surplus (deficit) (40,684,497)$ (29,543,172)$ (11,141,325)$ 38% (24,006,306)$ -$ (24,006,306)$ -$ 24,006,306$ Annual

CENTRAL COAST COMMUNITY ENERGY

BUDGETARY COMPARISON SCHEDULE
Current Month and Year Ended September 30, 2024
Current Month Variance
Favorable
(unfavorable)
Year-To-Date Variance
Favorable
(unfavorable)

CCA Program surplus/(deficit)
per budgetary comparison schedule: (24,006,306)$
Adjustments needed to reconcile to the changes in net position in the Statement of Revenues, Expenses and Changes in Net Position:

Add back GASB 87 lease amortization not in operating budget 300,424 Change in Net Position (23,705,882)$

REVENUES, EXPENSES AND CHANGES IN NET POSITION

CENTRAL COAST COMMUNITY ENERGY

BUDGET RECONCILIATION TO STATEMENT OF
Year Ended September 30, 2024

Budget Item YTD Variance Comment
Electric Sales Revenue (3.6%) Sales revenue includes revenues actually billed to customers as well as estimated customer usage during the reporting period that is not yet billed.

Cost of Energy 5.5% Variances in this category are typically due to (1) timing difference between projected and actual REC deliveries, (2) variance from actual to anticipated market prices, and (3) variance from actual to expected volume used by customers. Cost of energy includes scheduling coordinator fees for budget purposes only.

Staffing (17.9%) Staffing expenses are under budget due to the timing of new hires.

Professional Services (56.3%) This category includes accounting, IT, technical and other consultants.

Legal Costs (20.9%) This category includes outside legal costs for regulatory and energy procurement needs.

Marketing and customer enrollment 37.4% Variance is mostly due to the lower than anticipated costs of recent customer enrollments.

Data Management Services 3.5% These fees non-discretionary and are charged on a per customer basis.

Utility Service Fees (3.2%) These are PG&E and SCE fees charged on a per customer basis.

Other General & Administrative (45.4%) This category includes occupancy costs, industry membership dues, and other general and administrative costs.

Energy and Related Programs (25.0%) Programs expenses have generally been delayed until future periods Budget Commentary for significant items

CENTRAL COAST COMMUNITY ENERGY
October 1, 2023 through September 30, 2024

-66.6%
-52.3%
Act
Bud
$33.3
-$4.4
$62.7
$36.1
-$20.0
$0.0
$20.0
$40.0
$60.0
$80.0
$100.0
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
Actual
Budget
$544.4
$556.4
$0.0
$100.0
$200.0
$300.0
$400.0
$500.0
$600.0
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
Actual
Budget
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
Actual (T48/T8) 422 393 409 399 358 367 360 388 389 434 434 402 Budget 452 459 444 420 402 416 419 383 386 405 423 427
0 50
100
150
200
250
300
350
400
450
500

CUSTOMERS

SALES VOLUME
402 GWh

STD MARGIN
-$26.5M (-67%)
Δ in NET ASSETS
-$40.7M
Cumulative YTD Electricity Sales
Cumulative YTD Direct Margin
(Electricity Sales less Cost of Energy)
Data Definitions:

CUSTOMERS: Count of active customers from Calpine.

REPORTED / SALES VOLUME: Best available estimate of actual meter volume. Currently based on T+8 SQMD Report and T+48 when available.

REVENUE: Total Operating Revenue, net of uncollectible, (excludes Interest income).

ELECTRICITY SALES: Sales from electricity (net of uncollectible).

STD MARGIN: Electricity Sales less cost of energy (Forecasting & scheduling included in Cost of Energy to match budget) ACTUAL: Same as sales volume above
BUDGET: Volumes from FY23/24 budget
Monthly Sales Volume (GWh)
Financial Dashboard: September 2024

CUSTOMERS
460,000
ACTIVE
September revenue of $58.8M accounts for
402 GWh in net retail consumption, 25 GWh
below budget.

YTD Electricity revenue is $544M compared
to budget of $556M. YTD Direct Margin
(defined as Electricity Sales less Cost of
Energy) of -$4.4M is below budget by
$40.1M driven by year-end REC and RA
activity.

The chart to the right shows volume
comparison to budgeted volume.

The charts below display cumulative
revenue and margin $ vs budget.
30%
47%
23%
36%
47%
17%
Res
Com
Ag
YTD Month
Revenue $58.8
C.O.E. $94.2
OpEx $5.2
Net Income -$40.7
-$37.7
-$26.5
Act
Bud
Margin $
10 33%
47%
21%
39%
45%
15%
Res
Com
Ag
YTD Month

REVENUE
$58.8M
Margin %

Return of Investments YTD Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep CASH AND CASH EQUIVALENTSRiver City Bank/ Chase - Money Market and other Interest Earning AccountsFunds Invested - Average Balance 132,319,400$ 114,651,102$ 105,356,390$ 104,396,252$ 103,895,294$ 136,670,988$ 89,128,674$ 103,094,923$ 99,733,192$ 89,388,999$ 83,847,645$ 73,284,021$ Gains/Losses/Interest 4,143,997$ 406,536$ 345,045.39 356,733.82 348,153.12 328,669.77 467,310.22 292,100.83 359,957.02 342,604.48 323,544.31 306,632.12 266,709.39 Average APY 3.69% 3.61% 4.06% 4.00% 3.80% 4.10% 3.93% 4.19% 4.12% 4.34% 4.39% 4.37%INVESTMENTSRiver City Bank - Treasury-indexed productsFunds Invested - Average Balance 40,000,000$ 50,000,000$ 40,000,000$ 40,000,000$ 30,000,000$ 30,000,000$ 20,000,000$ 6,700,000$ -$ -$ -$ -$ Gains/Losses/Interest 1,277,633$ 178,385.54 213,485.85 236,035.13 205,868.28 193,103.80 116,602.81 103,270.38 30,881.04 - - - - Average APY 5.35% 5.12% 7.08% 6.18% 7.72% 4.66% 6.20% 5.53%RBC GAM / Principal Financal/ Schwab/FidelityFunds Invested - Average Balance 84,038,064$ 89,456,032$ 104,918,181$ 110,378,734$ 109,851,410$ 85,196,666$ 102,094,893$ 116,668,316$ 123,250,987$ 123,914,223$ 124,555,241$ 125,120,028$ Gains/Losses/Interest 6,246,237$ 351,852.83 417,968.37 462,148.76 463,382.88 411,214.03 409,319.23 398,176.83 488,291.25 481,788.55 572,560.60 582,989.80 1,206,544.05 Average APY 5.02% 5.61% 5.29% 5.04% 4.49% 5.77% 4.68% 5.02% 4.69% 5.54% 5.62% 11.57%

CENTRAL COAST COMMUNITY ENERGY
Investment Summary
October 1, 2023 through September 30, 2024

Current 0 - 30 Days 31 - 60 Days 61 - 90 Days > 91 Days A/R Balance 22,224,514$ 14,532,503$ 1,960,212$ 735,615$ 4,985,051$ 44,437,895$

CENTRAL COAST COMMUNITY ENERGY
Summary of Accounts Receivable, Net of Bad Debt Allowance As of September 30, 2024

Staff Report Item 12
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Juan Lopez, Director of Finance
SUBJECT: Adopt Resolution No. PB-2025-02 approving adjustments to the calendar year 2025 electric generation rates effective April 1, 2025
DATE: March 19, 2025
RECOMMENDATION:

It is recommended that the Policy Board adopt Resolution No. PB-2025-02 approving adjustments to the calendar year 2025 electric generation rates effective April 1, 2025.

BACKGROUND:

Since adopting a cost-of-service rate methodology in 2022, the Policy Board has approved generation rates designed to recover costs while working to maintain stable and competitive pricing compared to the investor-owned utilities (IOUs), Pacific Gas and Electric (PG&E) and Southern California Edison (SCE).

At its September 2024 meeting, where the Policy Board adopted the FY 2024-25 budget and 2025 calendar year rates, 3CE projected continued competitiveness across all customer classes due to lower estimated generation rates compared to the IOUs and anticipated reductions in Power Charge Indifference Adjustment (PCIA) rates. However, staff shared at that time that certain regulatory proceedings could impact 3CE’s cost recovery assumptions and competitive position, which may require further adjustment by the Board. Following the budget’s approval, those proceedings and other market developments did, in fact, impact 3CE’s cost recovery and rate competitiveness.

Due to the accelerated timeline of the annual Energy Resource Recovery Account (ERRA) proceeding, where the California Public Utilities Commission (CPUC) finalizes IOU rates and PCIA charges, 3CE was unable to fully evaluate the impact on competitiveness until final IOU rates were approved in late December 2024. As a result, the agency could not address these changes before budget development or the December Policy Board meeting.

The Audit and Finance Committee supported this proposal at its special meeting on February 27, 2025.

DISCUSSION/ANALYSIS:

Impact of PCIA Rates Changes on Competitiveness
After the adoption of 3CE’s 2025 generation rates, staff continued to assess the impact of significant PCIA rate changes implemented through the ERRA proceeding. While variances were expected, the magnitude of the final changes materially affected 3CE’s competitive position in PG&E and SCE service areas. These shifts stemmed from:
 Late Adjustments to Market Price Benchmarks (MPB): The MPB determines the market value of IOU legacy power contracts. Unexpected regulatory decisions and methodology changes contributed to a higher-than-anticipated PCIA for CCA customers.  Overhead Cost Allocation Change: The CPUC approved a shift of PG&E’s Energy Supply Administration overhead costs to Community Choice Aggregators (CCAs) like 3CE and Direct Access providers. 3CE’s PCIA forecasts in the fall did not anticipate CPUC approval of this proposal. However, the CPUC ultimately approved the revised cost allocation for 2025, increasing PCIA rates for 3CE customers.
 Recategorization of Resource Adequacy (RA): The CPUC proposed recategorizing RA from System to Local while applying a lower MPB to mitigate rate increases for SCE bundled customers. The CPUC’s approval of this change increased PCIA rates for CCA customers, as Local RA is valued lower than System RA, thereby shifting additional costs to departing load customers like 3CE.

These ERRA-related adjustments collectively increased PCIA rates for 3CE customers, negatively affecting rate competitiveness relative to the IOUs. In the PG&E service area, the PCIA rate increased by an average of about half a cent per kWh, while in the SCE service area, it rose by two cents per kWh, respectively, compared to the projected rate. In addition, lower generation rates approved by the CPUC resulted primarily from overcollections in the IOU balancing accounts, resulting in lower generation rates than initially estimated. At a system level, 3CE maintained a 5.2% competitive advantage over IOU rates.

Impact of Revised Load Volume
3CE’s cost-of-service rate design is based on assumptions regarding customer energy consumption. A reassessment of the forecasted retail load, based on historical forecast accuracy and updated weather projections, has led to a downward adjustment. The projected retail load for FY 2024-25 was revised from 5.7 million MWh to 5.5 million MWh. A downward adjustment to the retail load requires 3CE rates to recover rate revenue over a smaller base, increasing per-unit costs. Without rate adjustments, 3CE is expected to fall $12.4 million short of its $40.0 million reserve target for the fiscal year-end.

Proposed Rate Adjustments
To maintain financial stability and competitiveness, it is recommended that the Policy Board adopt adjustments to the calendar year 2025 electric generation rates effective April 1, 2025. These rate adjustments will ensure competitiveness systemwide across residential, commercial, and agricultural classes on average as of March 1, 2025. On average, adjusting rates will see residential customers 1% lower than the IOU generation rates, incorporating PCIA rates. On average, commercial and agricultural customers will see rates 3% lower than the IOUs, while standby and streetlight customers will see rates at parity. Attachment B to the Resolution contains the systemwide, single territory effective rates by class.

The proposed rate increase would average $0.004 per kWh across all customer classes, generating an additional $12.4 million in revenue across all customer classes over the last six months of FY 2024-25. As a systemwide average, this represents a 3% increase in electric generation rates. An average residential customer would see an impact of $1.60 in additional generation fees per month for the rest of the calendar year.

FISCAL IMPACT:

Adjusting 2025 generation rates will allow 3CE to recover costs based on revised load forecasts while ensuring that FY 2024-25 ends with $40.0 million in additional net position. This aligns with the agency’s three-year financial plan to meet its reserve targets outlined in the Financial Policies.

Maintaining a strong net position provides financial stability amid potential PCIA and market fluctuations, helps sustain a competitive rate structure that minimizes customer attrition, and supports a strong credit rating, reinforcing 3CE’s long-term financial resilience.

CONCLUSION:

To sustain financial health, cost recovery, and competitiveness rates, adjustment of 3CE generation rates is necessary in response to lower-than-projected energy volumes and recent regulatory and market changes affecting PCIA charges. By approving these adjustments, the Policy Board will ensure that 3CE remains competitive, financially stable, and aligned with its goal of meeting customers' energy demand with reliable and clean energy.

ATTACHMENT(S):

1. Draft Resolution No. PB-2025-02

DRAFT RESOLUTION NO. PB-2025-02

A RESOLUTION OF THE CENTRAL COAST COMMUNITY ENERGY POLICY BOARD OF DIRECTORS ADOPTING ADJUSTMENTS TO THE CALENDAR YEAR 2025 ELECTRIC GENERATION RATES EFFECTIVE APRIL 1, 2025
WHEREAS, Central Coast Community Energy (3CE) is a Joint Powers Authority (JPA) established and operated pursuant to California Government Code sections 6500 et seq. to study, promote, develop, conduct, operate, and manage energy programs in the California Central Coast region of Santa Cruz, Monterey, San Benito, Santa Barbara, and San Luis Obispo counties; and WHEREAS, 3CE is a community choice aggregator (CCA), as such term is defined in section 331.1 of the Public Utilities Code of the State of California (Public Utilities Code), that is a public agency, as such term is defined in the JPA law, which has implemented a CCA program pursuant to section 366.2 of the Public Utilities Code, and possesses the power to purchase and sell electric energy and enter related contracts for such purposes; and
WHEREAS, pursuant to sections 3.3.1 and 3.3.3 (d and f) of the Joint Exercise of Powers Agreement, as amended from time to time, the Policy Board is responsible for setting the 3CE electric generation rates consistent with California’s Constitution and applicable state law; and WHEREAS, at a duly noticed public meeting in June 2021, 3CE adopted Resolution No. PB-2021-05 adopting the cost-of-service rate design and approving rates to take effect Jan 1, 2022 through December 31, 2024. This resolution established rates based on the cost to serve customers in PG&E territory based on a cost-of-service analysis and rate design that maintained competitiveness with the incumbent investor-owned utilities (IOUs) and recovered the forecasted necessary revenue requirement for 3CE to operate; and
WHEREAS, 3CE, in consultation with a contracted independent rate design consultant developed a rate design based on a cost-of-service analysis (COSA) that allocates the 2025 revenue requirement to its customer classes and built proposed rate values for the individual customer rate codes; and WHEREAS, on June 26, 2024, at a publicly noticed meeting, the Policy Board approved Resolution No.

PB-2024-06 adopting the cost-of-service rate design methodology after conducting comprehensive outreach to customers; and
WHEREAS, on September 19, 2024, the Policy Board carefully considered the Staff Report and its accompanying exhibits, public comment, and customer input at its publicly noticed meeting. During this meeting, staff shared that the CPUC’s Regulatory Proceedings, including ERRA (Energy Resource Recovery Account) and PCIA (Power Charge Indifference Adjustment), could further impact 3CE’s cost recovery assumptions and competitive position, which may require further adjustment by the Policy Board. The Policy Board approved Resolution PB-2024-08 adopting 2025 generation rates; and WHEREAS, in adopting its 2025 rates, 3CE projected continued competitiveness across all customer classes due to lower estimated generation rates compared to the IOUs and anticipated reductions in PCIA rates; and
WHEREAS, following the electric generation rate approval (Resolution No. PB-2024-08), the Regulatory Proceedings, and other market developments impacted 3CE’s cost recovery and rate competitiveness that now necessitates 3CE to adjust rates at the rate schedule level to adjust for competitiveness by customer class and to adjust for a lower forecasted retail load volume; and

WHEREAS, the proposed adjustments to the electric generation rates, as set forth in this Resolution, have been calculated on the basis of the reasonable costs incurred by 3CE to provide electric service to its customers.

NOW, THEREFORE, THE CENTRAL COAST COMMUNITY ENERGY POLICY BOARD OF DIRECTORS DOES HEREBY RESOLVE, DETERMINE, AND ORDER AS FOLLOWS:

1. The Policy Board hereby finds:
a. The above recitals are true and correct and substantial evidence supports them. b. Notice of public meetings at which this Resolution was considered was properly given, and all oral and written presentations made to and heard by the Policy Board were properly considered.
c. Adjustments to the 2025 calendar year 3CE rate design were calculated by taking the average difference between the 3CE cost of service effective rates and the respective IOU’s effective rates as applied within each of the rates in the 3CE customer classes, which took effect January 1, 2025.
d. The Board finds that the proposed rates, as set out in Attachments A and B, are reasonable and in the best interest of 3CE customers.
e. The Policy Board finds that ensuring a reasonable cost competitive position, by customer class, to the IOUs is in the best interest of all 3CE customers, and further that distributing non-rate revenues to mitigate “opt-out” risk benefits all customer classes and is a reasonable and appropriate allocation methodology. f. The electric generation rates attached hereto as Attachments A and B:
i. Do not exceed the actual or estimated reasonable costs to 3CE for providing the services to which the fees related; and
ii. Are reasonable and necessary to enable 3CE to provide the benefit or privilege, service or product to which they related; and iii. Have been allocated in a manner such that the costs to the customer bear a fair and reasonable relationship to the customer’s burden on, or benefits received, from 3CE; and
iv. That this Resolution is not subject to the California Environmental Quality Act (“CEQA”) and, therefore, an environmental review is not required pursuant to Section 21080(b)(8) of the California Public Resources Code and Sections 15273(a) and 15061(b)(3) of the CEQA Guidelines, California Code of Regulations, Title 14, Chapter 3 because CEQA does not apply to the establishment, modification, restructuring, or approval of rates and other charges by public agencies for purposes such as those set forth herein.

2. The Policy Board hereby adopts:
a. The 3CE electrical rates, effective April 1, 2025, as set forth in Attachment B, attached hereto and incorporated herein by reference.

3. The Policy Board directs and authorizes:
a. Staff to monitor and determine when market or industry conditions beyond 3CE’s control require the approved cost of service model and subsequent 3CE customer rates to be modified between the annual evaluations.
b. The CEO to take such other and further actions as may be necessary and appropriate to implement the intent and purpose of this resolution. c. In the event of a fiscal emergency or the emergence of a significant shift in market or industry conditions threatening the fiscal stability of 3CE such that its credit rating or fiscal outlook is in danger of a downgrade, the Policy Board the Chief Executive Officer (CEO) to take immediate action to adjust the approved rates between

meetings of the Policy Board when needed to achieve the goals set by the Policy Board.
d. In the event of such fiscal emergency or threatened downgrade requiring the CEO to adjust rates between meetings of the Policy Board, the CEO to place a report on the agency of the next regular meeting of the Policy Board explaining the adjustment and the reasons for the adjustment and requesting that the Policy Board ratify the actions of the CEO.
e. This Resolution is adopted under the authority of the 3CE JPA and State law. If any section, subsection, clause or phrase is declared invalid or otherwise void by a court of competent jurisdiction, it shall not affect any remaining provision hereof. In this regard, the Policy Board finds and declares that it would have adopted this measure notwithstanding any partial invalidity hereof.

PASSED AND ADOPTED this 19th Day of March 2025, by the following vote:

AYES:

NOES:

ABSENT:
__________________________________
Chair, Fred Keeley
__________________________________
Board Clerk, Heather Vowell

ATTACHMENT A
3CE Single Territory Effective Generation Rates by Class 3CE Class
3CE Single Territory
Effective Gen Rates
April 1, 2025 ($/kWh)
Residential $ 0.14646
Small Commercial $ 0.13385
Medium Commercial $ 0.13410
Large Commercial $ 0.11732
Agricultural Sml/Med $ 0.13092
Agricultural Large $ 0.11988
Business Electric Vehicles $ 0.14807
Standby $ 0.09921
Lighting $ 0.11761

ATTACHMENT B
Proposed 3CE Rate Values by Rate Code and Time Period ($/kWh), effective April 1, 2025 3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Residential D Year-Round All $0.12246 $0.13046
Residential TOU-D-4 Summer On-Peak $0.26696 $0.27496
Residential TOU-D-4 Summer Mid-Peak $0.14246 $0.15046
Residential TOU-D-4 Summer Off-Peak $0.07675 $0.08475
Residential TOU-D-4 Winter Mid-Peak $0.18965 $0.19765
Residential TOU-D-4 Winter Off-Peak $0.10565 $0.11365
Residential TOU-D-4 Winter Super-Off-Peak $0.08559 $0.09359 Residential TOU-D-5 Summer On-Peak $0.42757 $0.43557
Residential TOU-D-5 Summer Mid-Peak $0.21894 $0.22694
Residential TOU-D-5 Summer Off-Peak $0.06669 $0.07469
Residential TOU-D-5 Winter Mid-Peak $0.28516 $0.29316
Residential TOU-D-5 Winter Off-Peak $0.10429 $0.11229
Residential TOU-D-5 Winter Super-Off-Peak $0.07497 $0.08297 Residential TOU-D-PRIME Summer On-Peak $0.31554 $0.32354 Residential TOU-D-PRIME Summer Mid-Peak $0.11229 $0.12029 Residential TOU-D-PRIME Summer Off-Peak $0.07497 $0.08297 Residential TOU-D-PRIME Winter Mid-Peak $0.27589 $0.28389 Residential TOU-D-PRIME Winter Off-Peak $0.06336 $0.07136 Residential TOU-D-PRIME Winter Super-Off-Peak $0.06336 $0.07136 Residential TOU-EV-1 Summer On-Peak $0.37291 $0.38091
Residential TOU-EV-1 Summer Off-Peak $0.05351 $0.06151
Residential TOU-EV-1 Winter On-Peak $0.16699 $0.17499
Residential TOU-EV-1 Winter Off-Peak $0.06630 $0.07430
Residential E-1 Year-Round All $0.14635 $0.15435
Residential E-ELEC Summer On-Peak $0.27680 $0.28480
Residential E-ELEC Summer Part-Peak $0.18327 $0.19127
Residential E-ELEC Summer Off-Peak $0.14071 $0.14871
Residential E-ELEC Winter On-Peak $0.12380 $0.13180
Residential E-ELEC Winter Part-Peak $0.10496 $0.11296
Residential E-ELEC Winter Off-Peak $0.09236 $0.10036
Residential E-TOU-B Summer On-Peak $0.25506 $0.26306
Residential E-TOU-B Summer Off-Peak $0.13983 $0.14783
Residential E-TOU-B Winter On-Peak $0.15580 $0.16380
Residential E-TOU-B Winter Off-Peak $0.11947 $0.12747
Residential E-TOU-C Summer On-Peak $0.21021 $0.21821
Residential E-TOU-C Summer Off-Peak $0.13233 $0.14033
Residential E-TOU-C Winter On-Peak $0.15386 $0.16186
Residential E-TOU-C Winter Off-Peak $0.12883 $0.13683

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Residential E-TOU-D Summer On-Peak $0.21966 $0.22766
Residential E-TOU-D Summer Off-Peak $0.12099 $0.12899
Residential E-TOU-D Winter On-Peak $0.18124 $0.18924
Residential E-TOU-D Winter Off-Peak $0.14826 $0.15626
Residential EV-A/B Summer On-Peak $0.29602 $0.30402
Residential EV-A/B Summer Part-Peak $0.16811 $0.17611
Residential EV-A/B Summer Off-Peak $0.12676 $0.13476
Residential EV-A/B Winter On-Peak $0.12264 $0.13064
Residential EV-A/B Winter Part-Peak $0.10049 $0.10849
Residential EV-A/B Winter Off-Peak $0.10049 $0.10849
Residential EV-2A Summer On-Peak $0.20233 $0.21033
Residential EV-2A Summer Part-Peak $0.16056 $0.16856
Residential EV-2A Summer Off-Peak $0.12213 $0.13013
Residential EV-2A Winter On-Peak $0.14920 $0.15720
Residential EV-2A Winter Part-Peak $0.13753 $0.14553
Residential EV-2A Winter Off-Peak $0.11560 $0.12360
Small Commercial TOU-GS-1-D-SEC Summer On-Peak $0.15170 $0.15970 Small Commercial TOU-GS-1-D-SEC Summer Mid-Peak $0.13700 $0.14500 Small Commercial TOU-GS-1-D-SEC Summer Off-Peak $0.08977 $0.09777 Small Commercial TOU-GS-1-D-SEC Winter Mid-Peak $0.14279 $0.15079 Small Commercial TOU-GS-1-D-SEC Winter Off-Peak $0.10081 $0.10881 Small Commercial TOU-GS-1-D-SEC Winter Super-Off-Peak $0.07543 $0.08343 Small Commercial TOU-GS-1-D-PRI Summer On-Peak $0.15059 $0.15859 Small Commercial TOU-GS-1-D-PRI Summer Mid-Peak $0.13593 $0.14393 Small Commercial TOU-GS-1-D-PRI Summer Off-Peak $0.08886 $0.09686 Small Commercial TOU-GS-1-D-PRI Winter Mid-Peak $0.14170 $0.14970 Small Commercial TOU-GS-1-D-PRI Winter Off-Peak $0.09987 $0.10787 Small Commercial TOU-GS-1-D-PRI Winter Super-Off-Peak $0.07456 $0.08256 Small Commercial TOU-GS-1-D-SUB Summer On-Peak $0.11432 $0.12232 Small Commercial TOU-GS-1-D-SUB Summer Mid-Peak $0.10407 $0.11207 Small Commercial TOU-GS-1-D-SUB Summer Off-Peak $0.07115 $0.07915 Small Commercial TOU-GS-1-D-SUB Winter Mid-Peak $0.10810 $0.11610 Small Commercial TOU-GS-1-D-SUB Winter Off-Peak $0.07884 $0.08684 Small Commercial TOU-GS-1-D-SUB Winter Super-Off-Peak $0.06114 $0.06914 Small Commercial
TOU-GS-1-D-TRANS Summer On-Peak $0.11430 $0.12230
Small Commercial
TOU-GS-1-D-TRANS Summer Mid-Peak $0.10405 $0.11205
Small Commercial
TOU-GS-1-D-TRANS Summer Off-Peak $0.07113 $0.07913
Small Commercial
TOU-GS-1-D-TRANS Winter Mid-Peak $0.10808 $0.11608

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Small Commercial
TOU-GS-1-D-TRANS Winter Off-Peak $0.07882 $0.08682
Small Commercial
TOU-GS-1-D-TRANS Winter Super-Off-Peak $0.06112 $0.06912 Small Commercial TOU-GS-1-E-SEC Summer On-Peak $0.43062 $0.43862 Small Commercial TOU-GS-1-E-SEC Summer Mid-Peak $0.11464 $0.12264 Small Commercial TOU-GS-1-E-SEC Summer Off-Peak $0.08196 $0.08996 Small Commercial TOU-GS-1-E-SEC Winter Mid-Peak $0.17399 $0.18199 Small Commercial TOU-GS-1-E-SEC Winter Off-Peak $0.09665 $0.10465 Small Commercial TOU-GS-1-E-SEC Winter Super-Off-Peak $0.05073 $0.05873 Small Commercial TOU-GS-1-E-PRI Summer On-Peak $0.42974 $0.43774 Small Commercial TOU-GS-1-E-PRI Summer Mid-Peak $0.11346 $0.12146 Small Commercial TOU-GS-1-E-PRI Summer Off-Peak $0.08074 $0.08874 Small Commercial TOU-GS-1-E-PRI Winter Mid-Peak $0.17287 $0.18087 Small Commercial TOU-GS-1-E-PRI Winter Off-Peak $0.09545 $0.10345 Small Commercial TOU-GS-1-E-PRI Winter Super-Off-Peak $0.04948 $0.05748 Small Commercial TOU-GS-1-E-SUB Summer On-Peak $0.40123 $0.40923 Small Commercial TOU-GS-1-E-SUB Summer Mid-Peak $0.11180 $0.11980 Small Commercial TOU-GS-1-E-SUB Summer Off-Peak $0.08186 $0.08986 Small Commercial TOU-GS-1-E-SUB Winter Mid-Peak $0.16616 $0.17416 Small Commercial TOU-GS-1-E-SUB Winter Off-Peak $0.09532 $0.10332 Small Commercial TOU-GS-1-E-SUB Winter Super-Off-Peak $0.05326 $0.06126 Small Commercial
TOU-GS-1-E-TRANS Summer On-Peak $0.40119 $0.40919
Small Commercial
TOU-GS-1-E-TRANS Summer Mid-Peak $0.11176 $0.11976
Small Commercial
TOU-GS-1-E-TRANS Summer Off-Peak $0.08183 $0.08983
Small Commercial
TOU-GS-1-E-TRANS Winter Mid-Peak $0.16613 $0.17413
Small Commercial
TOU-GS-1-E-TRANS Winter Off-Peak $0.09528 $0.10328
Small Commercial
TOU-GS-1-E-TRANS Winter Super-Off-Peak $0.05322 $0.06122 Small Commercial TOU-GS-1-ES-SEC Summer On-Peak $0.42966 $0.43766 Small Commercial TOU-GS-1-ES-SEC Summer Mid-Peak $0.12438 $0.13238 Small Commercial TOU-GS-1-ES-SEC Summer Off-Peak $0.08899 $0.09699 Small Commercial TOU-GS-1-ES-SEC Winter Mid-Peak $0.16205 $0.17005 Small Commercial TOU-GS-1-ES-SEC Winter Off-Peak $0.09204 $0.10004 Small Commercial TOU-GS-1-ES-SEC Winter Super-Off-Peak $0.05310 $0.06110 Small Commercial TOU-GS-1-ES-PRI Summer On-Peak $0.42847 $0.43647 Small Commercial TOU-GS-1-ES-PRI Summer Mid-Peak $0.12319 $0.13119 Small Commercial TOU-GS-1-ES-PRI Summer Off-Peak $0.08780 $0.09580

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Small Commercial TOU-GS-1-ES-PRI Winter Mid-Peak $0.16086 $0.16886 Small Commercial TOU-GS-1-ES-PRI Winter Off-Peak $0.09086 $0.09886 Small Commercial TOU-GS-1-ES-PRI Winter Super-Off-Peak $0.05192 $0.05992 Small Commercial TOU-GS-1-ES-SUB Summer On-Peak $0.42707 $0.43507 Small Commercial TOU-GS-1-ES-SUB Summer Mid-Peak $0.12179 $0.12979 Small Commercial TOU-GS-1-ES-SUB Summer Off-Peak $0.08640 $0.09440 Small Commercial TOU-GS-1-ES-SUB Winter Mid-Peak $0.15946 $0.16746 Small Commercial TOU-GS-1-ES-SUB Winter Off-Peak $0.08945 $0.09745 Small Commercial TOU-GS-1-ES-SUB Winter Super-Off-Peak $0.05051 $0.05851 Small Commercial
TOU-GS-1-ES-TRANS Summer On-Peak $0.42703 $0.43503
Small Commercial
TOU-GS-1-ES-TRANS Summer Mid-Peak $0.12175 $0.12975
Small Commercial
TOU-GS-1-ES-TRANS Summer Off-Peak $0.08636 $0.09436
Small Commercial
TOU-GS-1-ES-TRANS Winter Mid-Peak $0.15942 $0.16742
Small Commercial
TOU-GS-1-ES-TRANS Winter Off-Peak $0.08941 $0.09741
Small Commercial
TOU-GS-1-ES-TRANS Winter Super-Off-Peak $0.05047 $0.05847 Small Commercial TOU-GS-1-A Summer On-Peak $0.15465 $0.16265 Small Commercial TOU-GS-1-A Summer Mid-Peak $0.14464 $0.15264 Small Commercial TOU-GS-1-A Summer Off-Peak $0.13918 $0.14718 Small Commercial TOU-GS-1-A Winter Mid-Peak $0.10263 $0.11063 Small Commercial TOU-GS-1-A Winter Off-Peak $0.09237 $0.10037 Small Commercial TOU-GS-1-B Summer On-Peak $0.13746 $0.14546 Small Commercial TOU-GS-1-B Summer Mid-Peak $0.12858 $0.13658 Small Commercial TOU-GS-1-B Summer Off-Peak $0.12372 $0.13172 Small Commercial TOU-GS-1-B Winter Mid-Peak $0.16728 $0.17528 Small Commercial TOU-GS-1-B Winter Off-Peak $0.15055 $0.15855 Small Commercial B-1 Summer On-Peak $0.18998 $0.19798
Small Commercial B-1 Summer Part-Peak $0.14598 $0.15398 Small Commercial B-1 Summer Off-Peak $0.12738 $0.13538
Small Commercial B-1 Winter On-Peak $0.14060 $0.14860
Small Commercial B-1 Winter Off-Peak $0.12619 $0.13419
Small Commercial B-1 Winter Super-Off-Peak $0.11151 $0.11951 Small Commercial B-1-ST Summer On-Peak $0.19391 $0.20191 Small Commercial B-1-ST Summer Part-Peak $0.15604 $0.16404 Small Commercial B-1-ST Summer Off-Peak $0.12415 $0.13215 Small Commercial B-1-ST Winter On-Peak $0.14879 $0.15679 Small Commercial B-1-ST Winter Part-Peak $0.13779 $0.14579

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Small Commercial B-1-ST Winter Off-Peak $0.11816 $0.12616 Small Commercial B-1-ST Winter Super-Off-Peak $0.10351 $0.11151 Small Commercial B-6 Summer On-Peak $0.27293 $0.28093
Small Commercial B-6 Summer Off-Peak $0.12132 $0.12932
Small Commercial B-6 Winter On-Peak $0.14765 $0.15565
Small Commercial B-6 Winter Off-Peak $0.11236 $0.12036
Small Commercial B-6 Winter Super-Off-Peak $0.08017 $0.08817 Small Commercial A-1-A Year-Round All $0.13361 $0.14161 Small Commercial A-1-B Summer On-Peak $0.15382 $0.16182 Small Commercial A-1-B Summer Part-Peak $0.15382 $0.16182 Small Commercial A-1-B Summer Off-Peak $0.13175 $0.13975 Small Commercial A-1-B Winter Part-Peak $0.12636 $0.13436 Small Commercial A-1-B Winter Off-Peak $0.12584 $0.13384 Small Commercial A-6 Summer On-Peak $0.16614 $0.17414
Small Commercial A-6 Summer Part-Peak $0.16614 $0.17414 Small Commercial A-6 Summer Off-Peak $0.13602 $0.14402
Small Commercial A-6 Winter Part-Peak $0.12765 $0.13565 Small Commercial A-6 Winter Off-Peak $0.12701 $0.13501
Medium Commercial TOU-GS-2-D-SEC Summer On-Peak $0.43240 $0.44040 Medium Commercial TOU-GS-2-D-SEC Summer Mid-Peak $0.10389 $0.11189 Medium Commercial TOU-GS-2-D-SEC Summer Off-Peak $0.06666 $0.07466 Medium Commercial TOU-GS-2-D-SEC Winter Mid-Peak $0.13687 $0.14487 Medium Commercial TOU-GS-2-D-SEC Winter Off-Peak $0.07738 $0.08538 Medium Commercial TOU-GS-2-D-SEC Winter Super-Off-Peak $0.04063 $0.04863 Medium Commercial TOU-GS-2-D-PRI Summer On-Peak $0.42491 $0.43291 Medium Commercial TOU-GS-2-D-PRI Summer Mid-Peak $0.10313 $0.11113 Medium Commercial TOU-GS-2-D-PRI Summer Off-Peak $0.06583 $0.07383 Medium Commercial TOU-GS-2-D-PRI Winter Mid-Peak $0.13486 $0.14286 Medium Commercial TOU-GS-2-D-PRI Winter Off-Peak $0.07658 $0.08458 Medium Commercial TOU-GS-2-D-PRI Winter Super-Off-Peak $0.03976 $0.04776 Medium Commercial TOU-GS-2-D-SUB Summer On-Peak $0.41525 $0.42325 Medium Commercial TOU-GS-2-D-SUB Summer Mid-Peak $0.10222 $0.11022 Medium Commercial TOU-GS-2-D-SUB Summer Off-Peak $0.06484 $0.07284 Medium Commercial TOU-GS-2-D-SUB Winter Mid-Peak $0.13223 $0.14023 Medium Commercial TOU-GS-2-D-SUB Winter Off-Peak $0.07561 $0.08361 Medium Commercial TOU-GS-2-D-SUB Winter Super-Off-Peak $0.03872 $0.04672 Medium Commercial
TOU-GS-2-D-TRANS Summer On-Peak $0.41521 $0.42321
Medium Commercial
TOU-GS-2-D-TRANS Summer Mid-Peak $0.10221 $0.11021
Medium Commercial TOU-GS-2-D- Summer Off-Peak $0.06483 $0.07283

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
TRANS
Medium Commercial
TOU-GS-2-D-TRANS Winter Mid-Peak $0.13221 $0.14021
Medium Commercial
TOU-GS-2-D-TRANS Winter Off-Peak $0.07560 $0.08360
Medium Commercial
TOU-GS-2-D-TRANS Winter Super-Off-Peak $0.03871 $0.04671 Medium Commercial TOU-GS-2-E-SEC Summer On-Peak $0.49693 $0.50493 Medium Commercial TOU-GS-2-E-SEC Summer Mid-Peak $0.10329 $0.11129 Medium Commercial TOU-GS-2-E-SEC Summer Off-Peak $0.06627 $0.07427 Medium Commercial TOU-GS-2-E-SEC Winter Mid-Peak $0.15115 $0.15915 Medium Commercial TOU-GS-2-E-SEC Winter Off-Peak $0.07694 $0.08494 Medium Commercial TOU-GS-2-E-SEC Winter Super-Off-Peak $0.04039 $0.04839 Medium Commercial TOU-GS-2-E-PRI Summer On-Peak $0.49252 $0.50052 Medium Commercial TOU-GS-2-E-PRI Summer Mid-Peak $0.10208 $0.11008 Medium Commercial TOU-GS-2-E-PRI Summer Off-Peak $0.06500 $0.07300 Medium Commercial TOU-GS-2-E-PRI Winter Mid-Peak $0.14941 $0.15741 Medium Commercial TOU-GS-2-E-PRI Winter Off-Peak $0.07568 $0.08368 Medium Commercial TOU-GS-2-E-PRI Winter Super-Off-Peak $0.03908 $0.04708 Medium Commercial TOU-GS-2-E-SUB Summer On-Peak $0.49030 $0.49830 Medium Commercial TOU-GS-2-E-SUB Summer Mid-Peak $0.10036 $0.10836 Medium Commercial TOU-GS-2-E-SUB Summer Off-Peak $0.06328 $0.07128 Medium Commercial TOU-GS-2-E-SUB Winter Mid-Peak $0.14724 $0.15524 Medium Commercial TOU-GS-2-E-SUB Winter Off-Peak $0.07396 $0.08196 Medium Commercial TOU-GS-2-E-SUB Winter Super-Off-Peak $0.03736 $0.04536 Medium Commercial
TOU-GS-2-E-TRANS Summer On-Peak $0.49027 $0.49827
Medium Commercial
TOU-GS-2-E-TRANS Summer Mid-Peak $0.10034 $0.10834
Medium Commercial
TOU-GS-2-E-TRANS Summer Off-Peak $0.06326 $0.07126
Medium Commercial
TOU-GS-2-E-TRANS Winter Mid-Peak $0.14721 $0.15521
Medium Commercial
TOU-GS-2-E-TRANS Winter Off-Peak $0.07394 $0.08194
Medium Commercial
TOU-GS-2-E-TRANS Winter Super-Off-Peak $0.03734 $0.04534 Medium Commercial TOU-GS-2-B Summer On-Peak $0.32299 $0.33099 Medium Commercial TOU-GS-2-B Summer Mid-Peak $0.14680 $0.15480 Medium Commercial TOU-GS-2-B Summer Off-Peak $0.07410 $0.08210 Medium Commercial TOU-GS-2-B Winter Mid-Peak $0.10006 $0.10806 Medium Commercial TOU-GS-2-B Winter Off-Peak $0.05910 $0.06710 Medium Commercial TOU-GS-2-R Summer On-Peak $0.29164 $0.29964 Medium Commercial TOU-GS-2-R Summer Mid-Peak $0.13859 $0.14659

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Medium Commercial TOU-GS-2-R Summer Off-Peak $0.07839 $0.08639 Medium Commercial TOU-GS-2-R Winter Mid-Peak $0.10586 $0.11386 Medium Commercial TOU-GS-2-R Winter Off-Peak $0.06253 $0.07053 Medium Commercial TOU-GS-3-D-SEC Summer On-Peak $0.34913 $0.35713 Medium Commercial TOU-GS-3-D-SEC Summer Mid-Peak $0.09679 $0.10479 Medium Commercial TOU-GS-3-D-SEC Summer Off-Peak $0.06537 $0.07337 Medium Commercial TOU-GS-3-D-SEC Winter Mid-Peak $0.13840 $0.14640 Medium Commercial TOU-GS-3-D-SEC Winter Off-Peak $0.07590 $0.08390 Medium Commercial TOU-GS-3-D-SEC Winter Super-Off-Peak $0.03985 $0.04785 Medium Commercial TOU-GS-3-D-PRI Summer On-Peak $0.34322 $0.35122 Medium Commercial TOU-GS-3-D-PRI Summer Mid-Peak $0.09603 $0.10403 Medium Commercial TOU-GS-3-D-PRI Summer Off-Peak $0.06455 $0.07255 Medium Commercial TOU-GS-3-D-PRI Winter Mid-Peak $0.13613 $0.14413 Medium Commercial TOU-GS-3-D-PRI Winter Off-Peak $0.07509 $0.08309 Medium Commercial TOU-GS-3-D-PRI Winter Super-Off-Peak $0.03898 $0.04698 Medium Commercial TOU-GS-3-D-SUB Summer On-Peak $0.33955 $0.34755 Medium Commercial TOU-GS-3-D-SUB Summer Mid-Peak $0.09490 $0.10290 Medium Commercial TOU-GS-3-D-SUB Summer Off-Peak $0.06342 $0.07142 Medium Commercial TOU-GS-3-D-SUB Winter Mid-Peak $0.13407 $0.14207 Medium Commercial TOU-GS-3-D-SUB Winter Off-Peak $0.07396 $0.08196 Medium Commercial TOU-GS-3-D-SUB Winter Super-Off-Peak $0.03785 $0.04585 Medium Commercial
TOU-GS-3-D-TRANS Summer On-Peak $0.33944 $0.34744
Medium Commercial
TOU-GS-3-D-TRANS Summer Mid-Peak $0.09487 $0.10287
Medium Commercial
TOU-GS-3-D-TRANS Summer Off-Peak $0.06339 $0.07139
Medium Commercial
TOU-GS-3-D-TRANS Winter Mid-Peak $0.13401 $0.14201
Medium Commercial
TOU-GS-3-D-TRANS Winter Off-Peak $0.07393 $0.08193
Medium Commercial
TOU-GS-3-D-TRANS Winter Super-Off-Peak $0.03782 $0.04582 Medium Commercial TOU-GS-3-E-SEC Summer On-Peak $0.38543 $0.39343 Medium Commercial TOU-GS-3-E-SEC Summer Mid-Peak $0.09589 $0.10389 Medium Commercial TOU-GS-3-E-SEC Summer Off-Peak $0.06476 $0.07276 Medium Commercial TOU-GS-3-E-SEC Winter Mid-Peak $0.15696 $0.16496 Medium Commercial TOU-GS-3-E-SEC Winter Off-Peak $0.07518 $0.08318 Medium Commercial TOU-GS-3-E-SEC Winter Super-Off-Peak $0.03948 $0.04748 Medium Commercial TOU-GS-3-E-PRI Summer On-Peak $0.38331 $0.39131 Medium Commercial TOU-GS-3-E-PRI Summer Mid-Peak $0.09417 $0.10217 Medium Commercial TOU-GS-3-E-PRI Summer Off-Peak $0.06304 $0.07104

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Medium Commercial TOU-GS-3-E-PRI Winter Mid-Peak $0.15473 $0.16273 Medium Commercial TOU-GS-3-E-PRI Winter Off-Peak $0.07346 $0.08146 Medium Commercial TOU-GS-3-E-PRI Winter Super-Off-Peak $0.03776 $0.04576 Medium Commercial TOU-GS-3-E-SUB Summer On-Peak $0.38069 $0.38869 Medium Commercial TOU-GS-3-E-SUB Summer Mid-Peak $0.09205 $0.10005 Medium Commercial TOU-GS-3-E-SUB Summer Off-Peak $0.06092 $0.06892 Medium Commercial TOU-GS-3-E-SUB Winter Mid-Peak $0.15197 $0.15997 Medium Commercial TOU-GS-3-E-SUB Winter Off-Peak $0.07134 $0.07934 Medium Commercial TOU-GS-3-E-SUB Winter Super-Off-Peak $0.03564 $0.04364 Medium Commercial
TOU-GS-3-E-TRANS Summer On-Peak $0.38062 $0.38862
Medium Commercial
TOU-GS-3-E-TRANS Summer Mid-Peak $0.09200 $0.10000
Medium Commercial
TOU-GS-3-E-TRANS Summer Off-Peak $0.06087 $0.06887
Medium Commercial
TOU-GS-3-E-TRANS Winter Mid-Peak $0.15190 $0.15990
Medium Commercial
TOU-GS-3-E-TRANS Winter Off-Peak $0.07129 $0.07929
Medium Commercial
TOU-GS-3-E-TRANS Winter Super-Off-Peak $0.03559 $0.04359 Medium Commercial TOU-GS-3-B Summer On-Peak $0.27877 $0.28677 Medium Commercial TOU-GS-3-B Summer Mid-Peak $0.13113 $0.13913 Medium Commercial TOU-GS-3-B Summer Off-Peak $0.07081 $0.07881 Medium Commercial TOU-GS-3-B Winter Mid-Peak $0.09987 $0.10787 Medium Commercial TOU-GS-3-B Winter Off-Peak $0.05818 $0.06618 Medium Commercial TOU-GS-3-R Summer On-Peak $0.21363 $0.22163 Medium Commercial TOU-GS-3-R Summer Mid-Peak $0.11019 $0.11819 Medium Commercial TOU-GS-3-R Summer Off-Peak $0.07280 $0.08080 Medium Commercial TOU-GS-3-R Winter Mid-Peak $0.09876 $0.10676 Medium Commercial TOU-GS-3-R Winter Off-Peak $0.06152 $0.06952 Medium Commercial B-10-S Summer On-Peak $0.21511 $0.22311 Medium Commercial B-10-S Summer Part-Peak $0.15979 $0.16779 Medium Commercial B-10-S Summer Off-Peak $0.13059 $0.13859 Medium Commercial B-10-S Winter On-Peak $0.16307 $0.17107 Medium Commercial B-10-S Winter Off-Peak $0.13125 $0.13925 Medium Commercial B-10-S Winter Super-Off-Peak $0.09867 $0.10667 Medium Commercial B-10-P Summer On-Peak $0.19267 $0.20067 Medium Commercial B-10-P Summer Part-Peak $0.14095 $0.14895 Medium Commercial B-10-P Summer Off-Peak $0.11359 $0.12159 Medium Commercial B-10-P Winter On-Peak $0.14420 $0.15220 Medium Commercial B-10-P Winter Off-Peak $0.11436 $0.12236

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Medium Commercial B-10-P Winter Super-Off-Peak $0.08212 $0.09012 Medium Commercial B-10-T Summer On-Peak $0.17503 $0.18303 Medium Commercial B-10-T Summer Part-Peak $0.12008 $0.12808 Medium Commercial B-10-T Summer Off-Peak $0.09097 $0.09897 Medium Commercial B-10-T Winter On-Peak $0.12366 $0.13166 Medium Commercial B-10-T Winter Off-Peak $0.09187 $0.09987 Medium Commercial B-10-T Winter Super-Off-Peak $0.05668 $0.06468 Medium Commercial A-10-A-S Year-Round All $0.14324 $0.15124 Medium Commercial A-10-A-P Year-Round All $0.12406 $0.13206 Medium Commercial A-10-A-T Year-Round All $0.14324 $0.15124 Medium Commercial A-10-B-S Summer On-Peak $0.16469 $0.17269 Medium Commercial A-10-B-S Summer Part-Peak $0.16469 $0.17269 Medium Commercial A-10-B-S Summer Off-Peak $0.14076 $0.14876 Medium Commercial A-10-B-S Winter Part-Peak $0.13375 $0.14175 Medium Commercial A-10-B-S Winter Off-Peak $0.13312 $0.14112 Medium Commercial A-10-B-P Summer On-Peak $0.14721 $0.15521 Medium Commercial A-10-B-P Summer Part-Peak $0.14721 $0.15521 Medium Commercial A-10-B-P Summer Off-Peak $0.12269 $0.13069 Medium Commercial A-10-B-P Winter Part-Peak $0.11550 $0.12350 Medium Commercial A-10-B-P Winter Off-Peak $0.11486 $0.12286 Medium Commercial A-10-B-T Summer On-Peak $0.12535 $0.13335 Medium Commercial A-10-B-T Summer Part-Peak $0.12535 $0.13335 Medium Commercial A-10-B-T Summer Off-Peak $0.10148 $0.10948 Medium Commercial A-10-B-T Winter Part-Peak $0.09447 $0.10247 Medium Commercial A-10-B-T Winter Off-Peak $0.09383 $0.10183 Medium Commercial B-19-S Summer On-Peak $0.44528 $0.45328 Medium Commercial B-19-S Summer Part-Peak $0.17705 $0.18505 Medium Commercial B-19-S Summer Off-Peak $0.09082 $0.09882 Medium Commercial B-19-S Winter On-Peak $0.16906 $0.17706 Medium Commercial B-19-S Winter Off-Peak $0.09069 $0.09869 Medium Commercial B-19-S Winter Super-Off-Peak $0.02130 $0.02930 Medium Commercial B-19-P Summer On-Peak $0.36100 $0.36900 Medium Commercial B-19-P Summer Part-Peak $0.15069 $0.15869 Medium Commercial B-19-P Summer Off-Peak $0.07822 $0.08622 Medium Commercial B-19-P Winter On-Peak $0.14228 $0.15028 Medium Commercial B-19-P Winter Off-Peak $0.07861 $0.08661 Medium Commercial B-19-P Winter Super-Off-Peak $0.01312 $0.02112 Medium Commercial B-19-T Summer On-Peak $0.35378 $0.36178 Medium Commercial B-19-T Summer Part-Peak $0.14768 $0.15568 Medium Commercial B-19-T Summer Off-Peak $0.07666 $0.08466

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Medium Commercial B-19-T Winter On-Peak $0.13943 $0.14743 Medium Commercial B-19-T Winter Off-Peak $0.07704 $0.08504 Medium Commercial B-19-T Winter Super-Off-Peak $0.01286 $0.02086 Medium Commercial B-19-R-S Summer On-Peak $0.27490 $0.28290 Medium Commercial B-19-R-S Summer Part-Peak $0.15346 $0.16146 Medium Commercial B-19-R-S Summer Off-Peak $0.11897 $0.12697 Medium Commercial B-19-R-S Winter On-Peak $0.15681 $0.16481 Medium Commercial B-19-R-S Winter Off-Peak $0.11890 $0.12690 Medium Commercial B-19-R-S Winter Super-Off-Peak $0.08682 $0.09482 Medium Commercial B-19-R-P Summer On-Peak $0.24403 $0.25203 Medium Commercial B-19-R-P Summer Part-Peak $0.13317 $0.14117 Medium Commercial B-19-R-P Summer Off-Peak $0.10141 $0.10941 Medium Commercial B-19-R-P Winter On-Peak $0.13529 $0.14329 Medium Commercial B-19-R-P Winter Off-Peak $0.10150 $0.10950 Medium Commercial B-19-R-P Winter Super-Off-Peak $0.06936 $0.07736 Medium Commercial B-19-R-T Summer On-Peak $0.22170 $0.22970 Medium Commercial B-19-R-T Summer Part-Peak $0.14278 $0.15078 Medium Commercial B-19-R-T Summer Off-Peak $0.10197 $0.10997 Medium Commercial B-19-R-T Winter On-Peak $0.13478 $0.14278 Medium Commercial B-19-R-T Winter Off-Peak $0.10217 $0.11017 Medium Commercial B-19-R-T Winter Super-Off-Peak $0.06748 $0.07548 Medium Commercial B-19-S-S Summer On-Peak $0.28643 $0.29443 Medium Commercial B-19-S-S Summer Part-Peak $0.15515 $0.16315 Medium Commercial B-19-S-S Summer Off-Peak $0.11786 $0.12586 Medium Commercial B-19-S-S Winter On-Peak $0.15877 $0.16677 Medium Commercial B-19-S-S Winter Off-Peak $0.11779 $0.12579 Medium Commercial B-19-S-S Winter Super-Off-Peak $0.08310 $0.09110 Medium Commercial B-19-S-P Summer On-Peak $0.25257 $0.26057 Medium Commercial B-19-S-P Summer Part-Peak $0.13294 $0.14094 Medium Commercial B-19-S-P Summer Off-Peak $0.09867 $0.10667 Medium Commercial B-19-S-P Winter On-Peak $0.13524 $0.14324 Medium Commercial B-19-S-P Winter Off-Peak $0.09878 $0.10678 Medium Commercial B-19-S-P Winter Super-Off-Peak $0.06409 $0.07209 Medium Commercial B-19-S-T Summer On-Peak $0.22170 $0.22970 Medium Commercial B-19-S-T Summer Part-Peak $0.14278 $0.15078 Medium Commercial B-19-S-T Summer Off-Peak $0.10197 $0.10997 Medium Commercial B-19-S-T Winter On-Peak $0.13478 $0.14278 Medium Commercial B-19-S-T Winter Off-Peak $0.10217 $0.11017 Medium Commercial B-19-S-T Winter Super-Off-Peak $0.06748 $0.07548 Medium Commercial E-19-S Summer On-Peak $0.32965 $0.33765

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Medium Commercial E-19-S Summer Part-Peak $0.32965 $0.33765 Medium Commercial E-19-S Summer Off-Peak $0.09788 $0.10588 Medium Commercial E-19-S Winter Part-Peak $0.08888 $0.09688 Medium Commercial E-19-S Winter Off-Peak $0.08808 $0.09608 Medium Commercial E-19-P Summer On-Peak $0.30720 $0.31520 Medium Commercial E-19-P Summer Part-Peak $0.30720 $0.31520 Medium Commercial E-19-P Summer Off-Peak $0.09125 $0.09925 Medium Commercial E-19-P Winter Part-Peak $0.07555 $0.08355 Medium Commercial E-19-P Winter Off-Peak $0.07487 $0.08287 Medium Commercial E-19-T Summer On-Peak $0.27861 $0.28661 Medium Commercial E-19-T Summer Part-Peak $0.27861 $0.28661 Medium Commercial E-19-T Summer Off-Peak $0.08181 $0.08981 Medium Commercial E-19-T Winter Part-Peak $0.06738 $0.07538 Medium Commercial E-19-T Winter Off-Peak $0.06667 $0.07467 Medium Commercial E-19-R-S Summer On-Peak $0.16208 $0.17008 Medium Commercial E-19-R-S Summer Part-Peak $0.16208 $0.17008 Medium Commercial E-19-R-S Summer Off-Peak $0.13234 $0.14034 Medium Commercial E-19-R-S Winter Part-Peak $0.13002 $0.13802 Medium Commercial E-19-R-S Winter Off-Peak $0.12938 $0.13738 Medium Commercial E-19-R-P Summer On-Peak $0.13782 $0.14582 Medium Commercial E-19-R-P Summer Part-Peak $0.13782 $0.14582 Medium Commercial E-19-R-P Summer Off-Peak $0.11191 $0.11991 Medium Commercial E-19-R-P Winter Part-Peak $0.10973 $0.11773 Medium Commercial E-19-R-P Winter Off-Peak $0.10913 $0.11713 Medium Commercial E-19-R-T Summer On-Peak $0.13488 $0.14288 Medium Commercial E-19-R-T Summer Part-Peak $0.13488 $0.14288 Medium Commercial E-19-R-T Summer Off-Peak $0.11003 $0.11803 Medium Commercial E-19-R-T Winter Part-Peak $0.10768 $0.11568 Medium Commercial E-19-R-T Winter Off-Peak $0.10704 $0.11504 Large Commercial TOU-8-SEC-D Summer On-Peak $0.33112 $0.33912 Large Commercial TOU-8-SEC-D Summer Mid-Peak $0.09672 $0.10472 Large Commercial TOU-8-SEC-D Summer Off-Peak $0.06552 $0.07352 Large Commercial TOU-8-SEC-D Winter Mid-Peak $0.12196 $0.12996 Large Commercial TOU-8-SEC-D Winter Off-Peak $0.07610 $0.08410 Large Commercial TOU-8-SEC-D Winter Super-Off-Peak $0.03993 $0.04793 Large Commercial TOU-8-PRI-D Summer On-Peak $0.28973 $0.29773 Large Commercial TOU-8-PRI-D Summer Mid-Peak $0.09187 $0.09987 Large Commercial TOU-8-PRI-D Summer Off-Peak $0.06212 $0.07012 Large Commercial TOU-8-PRI-D Winter Mid-Peak $0.12193 $0.12993 Large Commercial TOU-8-PRI-D Winter Off-Peak $0.07244 $0.08044

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Large Commercial TOU-8-PRI-D Winter Super-Off-Peak $0.03800 $0.04600 Large Commercial TOU-8-SUB-D Summer On-Peak $0.28394 $0.29194 Large Commercial TOU-8-SUB-D Summer Mid-Peak $0.09003 $0.09803 Large Commercial TOU-8-SUB-D Summer Off-Peak $0.06088 $0.06888 Large Commercial TOU-8-SUB-D Winter Mid-Peak $0.11949 $0.12749 Large Commercial TOU-8-SUB-D Winter Off-Peak $0.07099 $0.07899 Large Commercial TOU-8-SUB-D Winter Super-Off-Peak $0.03724 $0.04524 Large Commercial TOU-8-SEC-E Summer On-Peak $0.35464 $0.36264 Large Commercial TOU-8-SEC-E Summer Mid-Peak $0.09585 $0.10385 Large Commercial TOU-8-SEC-E Summer Off-Peak $0.06494 $0.07294 Large Commercial TOU-8-SEC-E Winter Mid-Peak $0.11869 $0.12669 Large Commercial TOU-8-SEC-E Winter Off-Peak $0.07541 $0.08341 Large Commercial TOU-8-SEC-E Winter Super-Off-Peak $0.03957 $0.04757 Large Commercial TOU-8-PRI-E Summer On-Peak $0.33159 $0.33959 Large Commercial TOU-8-PRI-E Summer Mid-Peak $0.09077 $0.09877 Large Commercial TOU-8-PRI-E Summer Off-Peak $0.06138 $0.06938 Large Commercial TOU-8-PRI-E Winter Mid-Peak $0.13609 $0.14409 Large Commercial TOU-8-PRI-E Winter Off-Peak $0.07157 $0.07957 Large Commercial TOU-8-PRI-E Winter Super-Off-Peak $0.03755 $0.04555 Large Commercial TOU-8-SUB-E Summer On-Peak $0.36472 $0.37272 Large Commercial TOU-8-SUB-E Summer Mid-Peak $0.08539 $0.09339 Large Commercial TOU-8-SUB-E Summer Off-Peak $0.05742 $0.06542 Large Commercial TOU-8-SUB-E Winter Mid-Peak $0.11939 $0.12739 Large Commercial TOU-8-SUB-E Winter Off-Peak $0.06725 $0.07525 Large Commercial TOU-8-SUB-E Winter Super-Off-Peak $0.03526 $0.04326 Large Commercial TOU-8-SEC-B Summer On-Peak $0.27439 $0.28239 Large Commercial TOU-8-SEC-B Summer Mid-Peak $0.13307 $0.14107 Large Commercial TOU-8-SEC-B Summer Off-Peak $0.07259 $0.08059 Large Commercial TOU-8-SEC-B Winter Mid-Peak $0.09516 $0.10316 Large Commercial TOU-8-SEC-B Winter Off-Peak $0.06225 $0.07025 Large Commercial TOU-8-PRI-B Summer On-Peak $0.24179 $0.24979 Large Commercial TOU-8-PRI-B Summer Mid-Peak $0.13316 $0.14116 Large Commercial TOU-8-PRI-B Summer Off-Peak $0.06910 $0.07710 Large Commercial TOU-8-PRI-B Winter Mid-Peak $0.09714 $0.10514 Large Commercial TOU-8-PRI-B Winter Off-Peak $0.06047 $0.06847 Large Commercial TOU-8-SUB-B Summer On-Peak $0.39304 $0.40104 Large Commercial TOU-8-SUB-B Summer Mid-Peak $0.14954 $0.15754 Large Commercial TOU-8-SUB-B Summer Off-Peak $0.06479 $0.07279 Large Commercial TOU-8-SUB-B Winter Mid-Peak $0.08987 $0.09787 Large Commercial TOU-8-SUB-B Winter Off-Peak $0.05730 $0.06530

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Large Commercial TOU-8-SEC-R Summer On-Peak $0.21486 $0.22286 Large Commercial TOU-8-SEC-R Summer Mid-Peak $0.10766 $0.11566 Large Commercial TOU-8-SEC-R Summer Off-Peak $0.07259 $0.08059 Large Commercial TOU-8-SEC-R Winter Mid-Peak $0.09516 $0.10316 Large Commercial TOU-8-SEC-R Winter Off-Peak $0.06225 $0.07025 Large Commercial TOU-8-PRI-R Summer On-Peak $0.20511 $0.21311 Large Commercial TOU-8-PRI-R Summer Mid-Peak $0.10015 $0.10815 Large Commercial TOU-8-PRI-R Summer Off-Peak $0.06910 $0.07710 Large Commercial TOU-8-PRI-R Winter Mid-Peak $0.09714 $0.10514 Large Commercial TOU-8-PRI-R Winter Off-Peak $0.06047 $0.06847 Large Commercial TOU-8-SUB-R Summer On-Peak $0.20314 $0.21114 Large Commercial TOU-8-SUB-R Summer Mid-Peak $0.09526 $0.10326 Large Commercial TOU-8-SUB-R Summer Off-Peak $0.06479 $0.07279 Large Commercial TOU-8-SUB-R Winter Mid-Peak $0.08987 $0.09787 Large Commercial TOU-8-SUB-R Winter Off-Peak $0.05730 $0.06530 Large Commercial TOU-8-SEC-RBU Summer On-Peak $0.35723 $0.36523 Large Commercial TOU-8-SEC-RBU Summer Mid-Peak $0.09534 $0.10334 Large Commercial TOU-8-SEC-RBU Summer Off-Peak $0.06759 $0.07559 Large Commercial TOU-8-SEC-RBU Winter Mid-Peak $0.13634 $0.14434 Large Commercial TOU-8-SEC-RBU Winter Off-Peak $0.07700 $0.08500 Large Commercial TOU-8-SEC-RBU Winter Super-Off-Peak $0.04483 $0.05283 Large Commercial TOU-8-PRI-RBU Summer On-Peak $0.31354 $0.32154 Large Commercial TOU-8-PRI-RBU Summer Mid-Peak $0.09057 $0.09857 Large Commercial TOU-8-PRI-RBU Summer Off-Peak $0.06419 $0.07219 Large Commercial TOU-8-PRI-RBU Winter Mid-Peak $0.13684 $0.14484 Large Commercial TOU-8-PRI-RBU Winter Off-Peak $0.07334 $0.08134 Large Commercial TOU-8-PRI-RBU Winter Super-Off-Peak $0.04281 $0.05081 Large Commercial TOU-8-SUB-RBU Summer On-Peak $0.51047 $0.51847 Large Commercial TOU-8-SUB-RBU Summer Mid-Peak $0.08525 $0.09325 Large Commercial TOU-8-SUB-RBU Summer Off-Peak $0.06014 $0.06814 Large Commercial TOU-8-SUB-RBU Winter Mid-Peak $0.15411 $0.16211 Large Commercial TOU-8-SUB-RBU Winter Off-Peak $0.06897 $0.07697 Large Commercial TOU-8-SUB-RBU Winter Super-Off-Peak $0.04026 $0.04826 Large Commercial B-20-S Summer On-Peak $0.41330 $0.42130 Large Commercial B-20-S Summer Part-Peak $0.16995 $0.17795 Large Commercial B-20-S Summer Off-Peak $0.08772 $0.09572 Large Commercial B-20-S Winter On-Peak $0.16626 $0.17426 Large Commercial B-20-S Winter Off-Peak $0.08744 $0.09544 Large Commercial B-20-S Winter Super-Off-Peak $0.01824 $0.02624 Large Commercial B-20-P Summer On-Peak $0.45463 $0.46263

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Large Commercial B-20-P Summer Part-Peak $0.18695 $0.19495 Large Commercial B-20-P Summer Off-Peak $0.08337 $0.09137 Large Commercial B-20-P Winter On-Peak $0.16000 $0.16800 Large Commercial B-20-P Winter Off-Peak $0.08180 $0.08980 Large Commercial B-20-P Winter Super-Off-Peak $0.01371 $0.02171 Large Commercial B-20-T Summer On-Peak $0.20976 $0.21776 Large Commercial B-20-T Summer Part-Peak $0.13108 $0.13908 Large Commercial B-20-T Summer Off-Peak $0.07653 $0.08453 Large Commercial B-20-T Winter On-Peak $0.13760 $0.14560 Large Commercial B-20-T Winter Off-Peak $0.07157 $0.07957 Large Commercial B-20-T Winter Super-Off-Peak $0.01288 $0.02088 Large Commercial B-20-R-S Summer On-Peak $0.26418 $0.27218 Large Commercial B-20-R-S Summer Part-Peak $0.14491 $0.15291 Large Commercial B-20-R-S Summer Off-Peak $0.11126 $0.11926 Large Commercial B-20-R-S Winter On-Peak $0.15043 $0.15843 Large Commercial B-20-R-S Winter Off-Peak $0.11114 $0.11914 Large Commercial B-20-R-S Winter Super-Off-Peak $0.07902 $0.08702 Large Commercial B-20-R-P Summer On-Peak $0.25297 $0.26097 Large Commercial B-20-R-P Summer Part-Peak $0.13683 $0.14483 Large Commercial B-20-R-P Summer Off-Peak $0.10557 $0.11357 Large Commercial B-20-R-P Winter On-Peak $0.14172 $0.14972 Large Commercial B-20-R-P Winter Off-Peak $0.10561 $0.11361 Large Commercial B-20-R-P Winter Super-Off-Peak $0.07340 $0.08140 Large Commercial B-20-R-T Summer On-Peak $0.25904 $0.26704 Large Commercial B-20-R-T Summer Part-Peak $0.14448 $0.15248 Large Commercial B-20-R-T Summer Off-Peak $0.09595 $0.10395 Large Commercial B-20-R-T Winter On-Peak $0.14433 $0.15233 Large Commercial B-20-R-T Winter Off-Peak $0.09313 $0.10113 Large Commercial B-20-R-T Winter Super-Off-Peak $0.06146 $0.06946 Large Commercial B-20-S-S Summer On-Peak $0.26418 $0.27218 Large Commercial B-20-S-S Summer Part-Peak $0.14491 $0.15291 Large Commercial B-20-S-S Summer Off-Peak $0.11126 $0.11926 Large Commercial B-20-S-S Winter On-Peak $0.15043 $0.15843 Large Commercial B-20-S-S Winter Off-Peak $0.11114 $0.11914 Large Commercial B-20-S-S Winter Super-Off-Peak $0.07902 $0.08702 Large Commercial B-20-S-P Summer On-Peak $0.25297 $0.26097 Large Commercial B-20-S-P Summer Part-Peak $0.13683 $0.14483 Large Commercial B-20-S-P Summer Off-Peak $0.10557 $0.11357 Large Commercial B-20-S-P Winter On-Peak $0.14172 $0.14972 Large Commercial B-20-S-P Winter Off-Peak $0.10561 $0.11361

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Large Commercial B-20-S-P Winter Super-Off-Peak $0.07340 $0.08140 Large Commercial B-20-S-T Summer On-Peak $0.25904 $0.26704 Large Commercial B-20-S-T Summer Part-Peak $0.14448 $0.15248 Large Commercial B-20-S-T Summer Off-Peak $0.09595 $0.10395 Large Commercial B-20-S-T Winter On-Peak $0.14433 $0.15233 Large Commercial B-20-S-T Winter Off-Peak $0.09313 $0.10113 Large Commercial B-20-S-T Winter Super-Off-Peak $0.06146 $0.06946 Large Commercial E-20-S Summer On-Peak $0.26243 $0.27043 Large Commercial E-20-S Summer Part-Peak $0.26243 $0.27043 Large Commercial E-20-S Summer Off-Peak $0.08891 $0.09691 Large Commercial E-20-S Winter Part-Peak $0.08600 $0.09400 Large Commercial E-20-S Winter Off-Peak $0.08520 $0.09320 Large Commercial E-20-P Summer On-Peak $0.25121 $0.25921 Large Commercial E-20-P Summer Part-Peak $0.25121 $0.25921 Large Commercial E-20-P Summer Off-Peak $0.08511 $0.09311 Large Commercial E-20-P Winter Part-Peak $0.08232 $0.09032 Large Commercial E-20-P Winter Off-Peak $0.08156 $0.08956 Large Commercial E-20-T Summer On-Peak $0.29366 $0.30166 Large Commercial E-20-T Summer Part-Peak $0.29366 $0.30166 Large Commercial E-20-T Summer Off-Peak $0.09949 $0.10749 Large Commercial E-20-T Winter Part-Peak $0.09623 $0.10423 Large Commercial E-20-T Winter Off-Peak $0.09534 $0.10334 Large Commercial E-20-R-S Summer On-Peak $0.15161 $0.15961 Large Commercial E-20-R-S Summer Part-Peak $0.15161 $0.15961 Large Commercial E-20-R-S Summer Off-Peak $0.12228 $0.13028 Large Commercial E-20-R-S Winter Part-Peak $0.11978 $0.12778 Large Commercial E-20-R-S Winter Off-Peak $0.11909 $0.12709 Large Commercial E-20-R-P Summer On-Peak $0.14711 $0.15511 Large Commercial E-20-R-P Summer Part-Peak $0.14711 $0.15511 Large Commercial E-20-R-P Summer Off-Peak $0.11664 $0.12464 Large Commercial E-20-R-P Winter Part-Peak $0.11426 $0.12226 Large Commercial E-20-R-P Winter Off-Peak $0.11361 $0.12161 Large Commercial E-20-R-T Summer On-Peak $0.14053 $0.14853 Large Commercial E-20-R-T Summer Part-Peak $0.14053 $0.14853 Large Commercial E-20-R-T Summer Off-Peak $0.11039 $0.11839 Large Commercial E-20-R-T Winter Part-Peak $0.10805 $0.11605 Large Commercial E-20-R-T Winter Off-Peak $0.10741 $0.11541 Sm & Med Agricultural TOU-PA-2-D-SEC Summer On-Peak $0.14223 $0.15023 Sm & Med Agricultural TOU-PA-2-D-SEC Summer Mid-Peak $0.12968 $0.13768 Sm & Med Agricultural TOU-PA-2-D-SEC Summer Off-Peak $0.08582 $0.09382

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Sm & Med Agricultural TOU-PA-2-D-SEC Winter Mid-Peak $0.11138 $0.11938 Sm & Med Agricultural TOU-PA-2-D-SEC Winter Off-Peak $0.08863 $0.09663 Sm & Med Agricultural TOU-PA-2-D-SEC Winter Super-Off-Peak $0.07570 $0.08370 Sm & Med Agricultural TOU-PA-2-D-PRI Summer On-Peak $0.11134 $0.11934 Sm & Med Agricultural TOU-PA-2-D-PRI Summer Mid-Peak $0.10229 $0.11029 Sm & Med Agricultural TOU-PA-2-D-PRI Summer Off-Peak $0.07066 $0.07866 Sm & Med Agricultural TOU-PA-2-D-PRI Winter Mid-Peak $0.08909 $0.09709 Sm & Med Agricultural TOU-PA-2-D-PRI Winter Off-Peak $0.07268 $0.08068 Sm & Med Agricultural TOU-PA-2-D-PRI Winter Super-Off-Peak $0.06337 $0.07137 Sm & Med Agricultural TOU-PA-2-D-SUB Summer On-Peak $0.11030 $0.11830 Sm & Med Agricultural TOU-PA-2-D-SUB Summer Mid-Peak $0.10125 $0.10925 Sm & Med Agricultural TOU-PA-2-D-SUB Summer Off-Peak $0.06962 $0.07762 Sm & Med Agricultural TOU-PA-2-D-SUB Winter Mid-Peak $0.08805 $0.09605 Sm & Med Agricultural TOU-PA-2-D-SUB Winter Off-Peak $0.07164 $0.07964 Sm & Med Agricultural TOU-PA-2-D-SUB Winter Super-Off-Peak $0.06233 $0.07033 Sm & Med Agricultural TOU-PA-2-D5-SEC Summer On-Peak $0.26948 $0.27748 Sm & Med Agricultural TOU-PA-2-D5-SEC Summer Mid-Peak $0.25418 $0.26218 Sm & Med Agricultural TOU-PA-2-D5-SEC Summer Off-Peak $0.07650 $0.08450 Sm & Med Agricultural TOU-PA-2-D5-SEC Winter Mid-Peak $0.10843 $0.11643 Sm & Med Agricultural TOU-PA-2-D5-SEC Winter Off-Peak $0.08629 $0.09429 Sm & Med Agricultural TOU-PA-2-D5-SEC Winter Super-Off-Peak $0.07368 $0.08168 Sm & Med Agricultural TOU-PA-2-D5-PRI Summer On-Peak $0.21303 $0.22103 Sm & Med Agricultural TOU-PA-2-D5-PRI Summer Mid-Peak $0.20144 $0.20944 Sm & Med Agricultural TOU-PA-2-D5-PRI Summer Off-Peak $0.06674 $0.07474 Sm & Med Agricultural TOU-PA-2-D5-PRI Winter Mid-Peak $0.09095 $0.09895 Sm & Med Agricultural TOU-PA-2-D5-PRI Winter Off-Peak $0.07417 $0.08217 Sm & Med Agricultural TOU-PA-2-D5-PRI Winter Super-Off-Peak $0.06460 $0.07260 Sm & Med Agricultural TOU-PA-2-D5-SUB Summer On-Peak $0.21196 $0.21996 Sm & Med Agricultural TOU-PA-2-D5-SUB Summer Mid-Peak $0.20037 $0.20837 Sm & Med Agricultural TOU-PA-2-D5-SUB Summer Off-Peak $0.06567 $0.07367 Sm & Med Agricultural TOU-PA-2-D5-SUB Winter Mid-Peak $0.08988 $0.09788 Sm & Med Agricultural TOU-PA-2-D5-SUB Winter Off-Peak $0.07310 $0.08110 Sm & Med Agricultural TOU-PA-2-D5-SUB Winter Super-Off-Peak $0.06353 $0.07153 Sm & Med Agricultural TOU-PA-2-E-SEC Summer On-Peak $0.38509 $0.39309 Sm & Med Agricultural TOU-PA-2-E-SEC Summer Mid-Peak $0.10431 $0.11231 Sm & Med Agricultural TOU-PA-2-E-SEC Summer Off-Peak $0.06903 $0.07703 Sm & Med Agricultural TOU-PA-2-E-SEC Winter Mid-Peak $0.10372 $0.11172 Sm & Med Agricultural TOU-PA-2-E-SEC Winter Off-Peak $0.08254 $0.09054 Sm & Med Agricultural TOU-PA-2-E-SEC Winter Super-Off-Peak $0.07048 $0.07848 Sm & Med Agricultural TOU-PA-2-E-PRI Summer On-Peak $0.35342 $0.36142

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Sm & Med Agricultural TOU-PA-2-E-PRI Summer Mid-Peak $0.10173 $0.10973 Sm & Med Agricultural TOU-PA-2-E-PRI Summer Off-Peak $0.07010 $0.07810 Sm & Med Agricultural TOU-PA-2-E-PRI Winter Mid-Peak $0.10120 $0.10920 Sm & Med Agricultural TOU-PA-2-E-PRI Winter Off-Peak $0.08221 $0.09021 Sm & Med Agricultural TOU-PA-2-E-PRI Winter Super-Off-Peak $0.07140 $0.07940 Sm & Med Agricultural TOU-PA-2-E-SUB Summer On-Peak $0.35175 $0.35975 Sm & Med Agricultural TOU-PA-2-E-SUB Summer Mid-Peak $0.10006 $0.10806 Sm & Med Agricultural TOU-PA-2-E-SUB Summer Off-Peak $0.06843 $0.07643 Sm & Med Agricultural TOU-PA-2-E-SUB Winter Mid-Peak $0.09953 $0.10753 Sm & Med Agricultural TOU-PA-2-E-SUB Winter Off-Peak $0.08054 $0.08854 Sm & Med Agricultural TOU-PA-2-E-SUB Winter Super-Off-Peak $0.06973 $0.07773 Sm & Med Agricultural TOU-PA-2-E5-SEC Summer On-Peak $0.64122 $0.64922 Sm & Med Agricultural TOU-PA-2-E5-SEC Summer Mid-Peak $0.21512 $0.22312 Sm & Med Agricultural TOU-PA-2-E5-SEC Summer Off-Peak $0.06475 $0.07275 Sm & Med Agricultural TOU-PA-2-E5-SEC Winter Mid-Peak $0.10427 $0.11227 Sm & Med Agricultural TOU-PA-2-E5-SEC Winter Off-Peak $0.08297 $0.09097 Sm & Med Agricultural TOU-PA-2-E5-SEC Winter Super-Off-Peak $0.07085 $0.07885 Sm & Med Agricultural TOU-PA-2-E5-PRI Summer On-Peak $0.58259 $0.59059 Sm & Med Agricultural TOU-PA-2-E5-PRI Summer Mid-Peak $0.20091 $0.20891 Sm & Med Agricultural TOU-PA-2-E5-PRI Summer Off-Peak $0.06621 $0.07421 Sm & Med Agricultural TOU-PA-2-E5-PRI Winter Mid-Peak $0.10162 $0.10962 Sm & Med Agricultural TOU-PA-2-E5-PRI Winter Off-Peak $0.08254 $0.09054 Sm & Med Agricultural TOU-PA-2-E5-PRI Winter Super-Off-Peak $0.07168 $0.07968 Sm & Med Agricultural TOU-PA-2-E5-SUB Summer On-Peak $0.58092 $0.58892 Sm & Med Agricultural TOU-PA-2-E5-SUB Summer Mid-Peak $0.19924 $0.20724 Sm & Med Agricultural TOU-PA-2-E5-SUB Summer Off-Peak $0.06455 $0.07255 Sm & Med Agricultural TOU-PA-2-E5-SUB Winter Mid-Peak $0.09995 $0.10795 Sm & Med Agricultural TOU-PA-2-E5-SUB Winter Off-Peak $0.08087 $0.08887 Sm & Med Agricultural TOU-PA-2-E5-SUB Winter Super-Off-Peak $0.07001 $0.07801 Sm & Med Agricultural TOU-PA-2-A Summer On-Peak $0.22725 $0.23525 Sm & Med Agricultural TOU-PA-2-A Summer Mid-Peak $0.10907 $0.11707 Sm & Med Agricultural TOU-PA-2-A Summer Off-Peak $0.07701 $0.08501 Sm & Med Agricultural TOU-PA-2-A Winter Mid-Peak $0.10177 $0.10977 Sm & Med Agricultural TOU-PA-2-A Winter Off-Peak $0.07053 $0.07853 Sm & Med Agricultural TOU-PA-2-B Summer On-Peak $0.08450 $0.09250 Sm & Med Agricultural TOU-PA-2-B Summer Mid-Peak $0.07882 $0.08682 Sm & Med Agricultural TOU-PA-2-B Summer Off-Peak $0.07701 $0.08501 Sm & Med Agricultural TOU-PA-2-B Winter Mid-Peak $0.10177 $0.10977 Sm & Med Agricultural TOU-PA-2-B Winter Off-Peak $0.07053 $0.07853 Sm & Med Agricultural AG-1-A Year-Round All $0.10418 $0.11218

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Sm & Med Agricultural AG-1-B Year-Round All $0.13641 $0.14441 Sm & Med Agricultural AG-RA Summer On-Peak $0.11004 $0.11804 Sm & Med Agricultural AG-RA Summer Off-Peak $0.11004 $0.11804 Sm & Med Agricultural AG-RA Winter Part-Peak $0.09399 $0.10199 Sm & Med Agricultural AG-RA Winter Off-Peak $0.09331 $0.10131 Sm & Med Agricultural AG-RB Summer On-Peak $0.09613 $0.10413 Sm & Med Agricultural AG-RB Summer Off-Peak $0.09613 $0.10413 Sm & Med Agricultural AG-RB Winter Part-Peak $0.08512 $0.09312 Sm & Med Agricultural AG-RB Winter Off-Peak $0.08443 $0.09243 Sm & Med Agricultural AG-F-A Summer On-Peak $0.20799 $0.21599 Sm & Med Agricultural AG-F-A Summer Off-Peak $0.13873 $0.14673 Sm & Med Agricultural AG-F-A Winter On-Peak $0.12957 $0.13757 Sm & Med Agricultural AG-F-A Winter Off-Peak $0.10582 $0.11382 Sm & Med Agricultural AG-F-B Summer On-Peak $0.23254 $0.24054 Sm & Med Agricultural AG-F-B Summer Off-Peak $0.15881 $0.16681 Sm & Med Agricultural AG-F-B Winter On-Peak $0.14787 $0.15587 Sm & Med Agricultural AG-F-B Winter Off-Peak $0.12389 $0.13189 Sm & Med Agricultural AG-VA Summer On-Peak $0.10439 $0.11239 Sm & Med Agricultural AG-VA Summer Off-Peak $0.10439 $0.11239 Sm & Med Agricultural AG-VA Winter Part-Peak $0.09107 $0.09907 Sm & Med Agricultural AG-VA Winter Off-Peak $0.09045 $0.09845 Sm & Med Agricultural AG-VB Summer On-Peak $0.09664 $0.10464 Sm & Med Agricultural AG-VB Summer Off-Peak $0.09664 $0.10464 Sm & Med Agricultural AG-VB Winter Part-Peak $0.08528 $0.09328 Sm & Med Agricultural AG-VB Winter Off-Peak $0.08463 $0.09263 Sm & Med Agricultural AG-4-A Summer On-Peak $0.10687 $0.11487 Sm & Med Agricultural AG-4-A Summer Off-Peak $0.10687 $0.11487 Sm & Med Agricultural AG-4-A Winter Part-Peak $0.09433 $0.10233 Sm & Med Agricultural AG-4-A Winter Off-Peak $0.09370 $0.10170 Sm & Med Agricultural AG-4-B Summer On-Peak $0.12124 $0.12924 Sm & Med Agricultural AG-4-B Summer Off-Peak $0.12124 $0.12924 Sm & Med Agricultural AG-4-B Winter Part-Peak $0.10865 $0.11665 Sm & Med Agricultural AG-4-B Winter Off-Peak $0.10803 $0.11603 Sm & Med Agricultural AG-5-A Summer On-Peak $0.11853 $0.12653 Sm & Med Agricultural AG-5-A Summer Off-Peak $0.11853 $0.12653 Sm & Med Agricultural AG-5-A Winter Part-Peak $0.10740 $0.11540 Sm & Med Agricultural AG-5-A Winter Off-Peak $0.10676 $0.11476 Sm & Med Agricultural AG-5-B Summer On-Peak $0.10434 $0.11234 Sm & Med Agricultural AG-5-B Summer Off-Peak $0.10434 $0.11234 Sm & Med Agricultural AG-5-B Winter Part-Peak $0.09341 $0.10141

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Sm & Med Agricultural AG-5-B Winter Off-Peak $0.09281 $0.10081 Sm & Med Agricultural AG-A-1 Summer On-Peak $0.23860 $0.24660 Sm & Med Agricultural AG-A-1 Summer Off-Peak $0.13166 $0.13966 Sm & Med Agricultural AG-A-1 Winter On-Peak $0.12869 $0.13669 Sm & Med Agricultural AG-A-1 Winter Off-Peak $0.10505 $0.11305 Sm & Med Agricultural AG-A-2 Summer On-Peak $0.23862 $0.24662 Sm & Med Agricultural AG-A-2 Summer Off-Peak $0.13167 $0.13967 Sm & Med Agricultural AG-A-2 Winter On-Peak $0.12870 $0.13670 Sm & Med Agricultural AG-A-2 Winter Off-Peak $0.10506 $0.11306 Sm & Med Agricultural AG-B Summer On-Peak $0.26130 $0.26930 Sm & Med Agricultural AG-B Summer Off-Peak $0.15003 $0.15803 Sm & Med Agricultural AG-B Winter On-Peak $0.14520 $0.15320 Sm & Med Agricultural AG-B Winter Off-Peak $0.12151 $0.12951 Large Agricultural TOU-PA-3-D-SEC Summer On-Peak $0.24461 $0.25261 Large Agricultural TOU-PA-3-D-SEC Summer Mid-Peak $0.09291 $0.10091 Large Agricultural TOU-PA-3-D-SEC Summer Off-Peak $0.06155 $0.06955 Large Agricultural TOU-PA-3-D-SEC Winter Mid-Peak $0.10142 $0.10942 Large Agricultural TOU-PA-3-D-SEC Winter Off-Peak $0.07927 $0.08727 Large Agricultural TOU-PA-3-D-SEC Winter Super-Off-Peak $0.04169 $0.04969 Large Agricultural TOU-PA-3-D-PRI Summer On-Peak $0.24229 $0.25029 Large Agricultural TOU-PA-3-D-PRI Summer Mid-Peak $0.09194 $0.09994 Large Agricultural TOU-PA-3-D-PRI Summer Off-Peak $0.06058 $0.06858 Large Agricultural TOU-PA-3-D-PRI Winter Mid-Peak $0.10018 $0.10818 Large Agricultural TOU-PA-3-D-PRI Winter Off-Peak $0.07830 $0.08630 Large Agricultural TOU-PA-3-D-PRI Winter Super-Off-Peak $0.04072 $0.04872 Large Agricultural TOU-PA-3-D-SUB Summer On-Peak $0.26085 $0.26885 Large Agricultural TOU-PA-3-D-SUB Summer Mid-Peak $0.08896 $0.09696 Large Agricultural TOU-PA-3-D-SUB Summer Off-Peak $0.06152 $0.06952 Large Agricultural TOU-PA-3-D-SUB Winter Mid-Peak $0.11066 $0.11866 Large Agricultural TOU-PA-3-D-SUB Winter Off-Peak $0.07703 $0.08503 Large Agricultural TOU-PA-3-D-SUB Winter Super-Off-Peak $0.04414 $0.05214 Large Agricultural TOU-PA-3-D5-SEC Summer On-Peak $0.49388 $0.50188 Large Agricultural TOU-PA-3-D5-SEC Summer Mid-Peak $0.17338 $0.18138 Large Agricultural TOU-PA-3-D5-SEC Summer Off-Peak $0.06020 $0.06820 Large Agricultural TOU-PA-3-D5-SEC Winter Mid-Peak $0.11246 $0.12046 Large Agricultural TOU-PA-3-D5-SEC Winter Off-Peak $0.07827 $0.08627 Large Agricultural TOU-PA-3-D5-SEC Winter Super-Off-Peak $0.04560 $0.05360 Large Agricultural TOU-PA-3-D5-PRI Summer On-Peak $0.49161 $0.49961 Large Agricultural TOU-PA-3-D5-PRI Summer Mid-Peak $0.17254 $0.18054 Large Agricultural TOU-PA-3-D5-PRI Summer Off-Peak $0.05935 $0.06735

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Large Agricultural TOU-PA-3-D5-PRI Winter Mid-Peak $0.11124 $0.11924 Large Agricultural TOU-PA-3-D5-PRI Winter Off-Peak $0.07743 $0.08543 Large Agricultural TOU-PA-3-D5-PRI Winter Super-Off-Peak $0.04476 $0.05276 Large Agricultural TOU-PA-3-D5-SUB Summer On-Peak $0.48888 $0.49688 Large Agricultural TOU-PA-3-D5-SUB Summer Mid-Peak $0.17152 $0.17952 Large Agricultural TOU-PA-3-D5-SUB Summer Off-Peak $0.05834 $0.06634 Large Agricultural TOU-PA-3-D5-SUB Winter Mid-Peak $0.10978 $0.11778 Large Agricultural TOU-PA-3-D5-SUB Winter Off-Peak $0.07642 $0.08442 Large Agricultural TOU-PA-3-D5-SUB Winter Super-Off-Peak $0.04375 $0.05175 Large Agricultural TOU-PA-3-E-SEC Summer On-Peak $0.33570 $0.34370 Large Agricultural TOU-PA-3-E-SEC Summer Mid-Peak $0.09238 $0.10038 Large Agricultural TOU-PA-3-E-SEC Summer Off-Peak $0.06120 $0.06920 Large Agricultural TOU-PA-3-E-SEC Winter Mid-Peak $0.11182 $0.11982 Large Agricultural TOU-PA-3-E-SEC Winter Off-Peak $0.08908 $0.09708 Large Agricultural TOU-PA-3-E-SEC Winter Super-Off-Peak $0.03242 $0.04042 Large Agricultural TOU-PA-3-E-PRI Summer On-Peak $0.30366 $0.31166 Large Agricultural TOU-PA-3-E-PRI Summer Mid-Peak $0.08952 $0.09752 Large Agricultural TOU-PA-3-E-PRI Summer Off-Peak $0.06208 $0.07008 Large Agricultural TOU-PA-3-E-PRI Winter Mid-Peak $0.10663 $0.11463 Large Agricultural TOU-PA-3-E-PRI Winter Off-Peak $0.08662 $0.09462 Large Agricultural TOU-PA-3-E-PRI Winter Super-Off-Peak $0.03676 $0.04476 Large Agricultural TOU-PA-3-E-SUB Summer On-Peak $0.30201 $0.31001 Large Agricultural TOU-PA-3-E-SUB Summer Mid-Peak $0.08787 $0.09587 Large Agricultural TOU-PA-3-E-SUB Summer Off-Peak $0.06043 $0.06843 Large Agricultural TOU-PA-3-E-SUB Winter Mid-Peak $0.10498 $0.11298 Large Agricultural TOU-PA-3-E-SUB Winter Off-Peak $0.08497 $0.09297 Large Agricultural TOU-PA-3-E-SUB Winter Super-Off-Peak $0.03511 $0.04311 Large Agricultural TOU-PA-3-E5-SEC Summer On-Peak $0.49415 $0.50215 Large Agricultural TOU-PA-3-E5-SEC Summer Mid-Peak $0.17338 $0.18138 Large Agricultural TOU-PA-3-E5-SEC Summer Off-Peak $0.06020 $0.06820 Large Agricultural TOU-PA-3-E5-SEC Winter Mid-Peak $0.11248 $0.12048 Large Agricultural TOU-PA-3-E5-SEC Winter Off-Peak $0.09154 $0.09954 Large Agricultural TOU-PA-3-E5-SEC Winter Super-Off-Peak $0.03938 $0.04738 Large Agricultural TOU-PA-3-E5-PRI Summer On-Peak $0.49284 $0.50084 Large Agricultural TOU-PA-3-E5-PRI Summer Mid-Peak $0.17207 $0.18007 Large Agricultural TOU-PA-3-E5-PRI Summer Off-Peak $0.05889 $0.06689 Large Agricultural TOU-PA-3-E5-PRI Winter Mid-Peak $0.11117 $0.11917 Large Agricultural TOU-PA-3-E5-PRI Winter Off-Peak $0.09023 $0.09823 Large Agricultural TOU-PA-3-E5-PRI Winter Super-Off-Peak $0.03807 $0.04607 Large Agricultural TOU-PA-3-E5-SUB Summer On-Peak $0.49119 $0.49919

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Large Agricultural TOU-PA-3-E5-SUB Summer Mid-Peak $0.17042 $0.17842 Large Agricultural TOU-PA-3-E5-SUB Summer Off-Peak $0.05724 $0.06524 Large Agricultural TOU-PA-3-E5-SUB Winter Mid-Peak $0.10952 $0.11752 Large Agricultural TOU-PA-3-E5-SUB Winter Off-Peak $0.08859 $0.09659 Large Agricultural TOU-PA-3-E5-SUB Winter Super-Off-Peak $0.03642 $0.04442 Large Agricultural TOU-PA-3-A Summer On-Peak $0.19874 $0.20674 Large Agricultural TOU-PA-3-A Summer Mid-Peak $0.09488 $0.10288 Large Agricultural TOU-PA-3-A Summer Off-Peak $0.06808 $0.07608 Large Agricultural TOU-PA-3-A Winter Mid-Peak $0.08888 $0.09688 Large Agricultural TOU-PA-3-A Winter Off-Peak $0.06482 $0.07282 Large Agricultural TOU-PA-3-B Summer On-Peak $0.20106 $0.20906 Large Agricultural TOU-PA-3-B Summer Mid-Peak $0.06957 $0.07757 Large Agricultural TOU-PA-3-B Summer Off-Peak $0.06808 $0.07608 Large Agricultural TOU-PA-3-B Winter Mid-Peak $0.12843 $0.13643 Large Agricultural TOU-PA-3-B Winter Off-Peak $0.06482 $0.07282 Large Agricultural AG-4-C Summer On-Peak $0.07159 $0.07959 Large Agricultural AG-4-C Summer Part-Peak $0.07159 $0.07959 Large Agricultural AG-4-C Summer Off-Peak $0.06397 $0.07197 Large Agricultural AG-4-C Winter Part-Peak $0.06221 $0.07021 Large Agricultural AG-4-C Winter Off-Peak $0.06172 $0.06972 Large Agricultural AG-5-C Summer On-Peak $0.09342 $0.10142 Large Agricultural AG-5-C Summer Part-Peak $0.07876 $0.08676 Large Agricultural AG-5-C Summer Off-Peak $0.07360 $0.08160 Large Agricultural AG-5-C Winter Part-Peak $0.07140 $0.07940 Large Agricultural AG-5-C Winter Off-Peak $0.07080 $0.07880 Large Agricultural AG-C Summer On-Peak $0.14621 $0.15421 Large Agricultural AG-C Summer Off-Peak $0.11482 $0.12282 Large Agricultural AG-C Winter On-Peak $0.13062 $0.13862 Large Agricultural AG-C Winter Off-Peak $0.10344 $0.11144 Large Agricultural AG-F-C Summer On-Peak $0.19350 $0.20150 Large Agricultural AG-F-C Summer Off-Peak $0.14575 $0.15375 Large Agricultural AG-F-C Winter On-Peak $0.16700 $0.17500 Large Agricultural AG-F-C Winter Off-Peak $0.13210 $0.14010 Business Electric
Vehicles TOU-EV-7 Summer On-Peak $0.32841 $0.33641
Business Electric
Vehicles TOU-EV-7 Summer Mid-Peak $0.11658 $0.12458
Business Electric
Vehicles TOU-EV-7 Summer Off-Peak $0.09580 $0.10380
Business Electric
Vehicles TOU-EV-7 Winter Mid-Peak $0.17693 $0.18493
Business Electric TOU-EV-7 Winter Off-Peak $0.11270 $0.12070

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Vehicles
Business Electric
Vehicles TOU-EV-7 Winter Super-Off-Peak $0.05159 $0.05959 Business Electric
Vehicles TOU-EV-8 Summer On-Peak $0.36116 $0.36916
Business Electric
Vehicles TOU-EV-8 Summer Mid-Peak $0.10255 $0.11055
Business Electric
Vehicles TOU-EV-8 Summer Off-Peak $0.07933 $0.08733
Business Electric
Vehicles TOU-EV-8 Winter Mid-Peak $0.14778 $0.15578
Business Electric
Vehicles TOU-EV-8 Winter Off-Peak $0.09324 $0.10124
Business Electric
Vehicles TOU-EV-8 Winter Super-Off-Peak $0.04010 $0.04810 Business Electric
Vehicles TOU-EV-9-SEC Summer On-Peak $0.28269 $0.29069
Business Electric
Vehicles TOU-EV-9-SEC Summer Mid-Peak $0.09580 $0.10380 Business Electric
Vehicles TOU-EV-9-SEC Summer Off-Peak $0.07439 $0.08239 Business Electric
Vehicles TOU-EV-9-SEC Winter Mid-Peak $0.13945 $0.14745 Business Electric
Vehicles TOU-EV-9-SEC Winter Off-Peak $0.08540 $0.09340 Business Electric
Vehicles TOU-EV-9-SEC Winter Super-Off-Peak $0.03955 $0.04755 Business Electric
Vehicles TOU-EV-9-PRI Summer On-Peak $0.23893 $0.24693
Business Electric
Vehicles TOU-EV-9-PRI Summer Mid-Peak $0.09056 $0.09856 Business Electric
Vehicles TOU-EV-9-PRI Summer Off-Peak $0.07145 $0.07945 Business Electric
Vehicles TOU-EV-9-PRI Winter Mid-Peak $0.13227 $0.14027 Business Electric
Vehicles TOU-EV-9-PRI Winter Off-Peak $0.08045 $0.08845 Business Electric
Vehicles TOU-EV-9-PRI Winter Super-Off-Peak $0.04280 $0.05080 Business Electric
Vehicles TOU-EV-9-SUB Summer On-Peak $0.23269 $0.24069
Business Electric
Vehicles TOU-EV-9-SUB Summer Mid-Peak $0.08523 $0.09323 Business Electric
Vehicles TOU-EV-9-SUB Summer Off-Peak $0.06672 $0.07472 Business Electric
Vehicles TOU-EV-9-SUB Winter Mid-Peak $0.11778 $0.12578 Business Electric
Vehicles TOU-EV-9-SUB Winter Off-Peak $0.07476 $0.08276

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Business Electric
Vehicles TOU-EV-9-SUB Winter Super-Off-Peak $0.04025 $0.04825 Business Electric
Vehicles B-EV-1-S Year-Round On-Peak $0.26839 $0.27639
Business Electric
Vehicles B-EV-1-S Year-Round Off-Peak $0.10408 $0.11208 Business Electric
Vehicles B-EV-1-S
Year-Round Super-Off-Peak $0.08122 $0.08922
Business Electric
Vehicles B-EV-2-S Year-Round On-Peak $0.28664 $0.29464
Business Electric
Vehicles B-EV-2-S Year-Round Off-Peak $0.10302 $0.11102 Business Electric
Vehicles B-EV-2-S
Year-Round Super-Off-Peak $0.08009 $0.08809
Business Electric
Vehicles B-EV-2-P Year-Round On-Peak $0.28613 $0.29413
Business Electric
Vehicles B-EV-2-P Year-Round Off-Peak $0.09687 $0.10487 Business Electric
Vehicles B-EV-2-P
Year-Round Super-Off-Peak $0.07350 $0.08150
Standby SB-S Summer On-Peak $0.13600 $0.14400
Standby SB-S Summer Part-Peak $0.12371 $0.13171
Standby SB-S Summer Off-Peak $0.11004 $0.11804
Standby SB-S Winter On-Peak $0.13108 $0.13908
Standby SB-S Winter Off-Peak $0.11120 $0.11920
Standby SB-S Winter Super-Off-Peak $0.06705 $0.07505
Standby SB-P Summer On-Peak $0.13457 $0.14257
Standby SB-P Summer Part-Peak $0.12308 $0.13108
Standby SB-P Summer Off-Peak $0.11030 $0.11830
Standby SB-P Winter On-Peak $0.12997 $0.13797
Standby SB-P Winter Off-Peak $0.11138 $0.11938
Standby SB-P Winter Super-Off-Peak $0.07012 $0.07812
Standby SB-T Summer On-Peak $0.11155 $0.11955
Standby SB-T Summer Part-Peak $0.10054 $0.10854
Standby SB-T Summer Off-Peak $0.08829 $0.09629
Standby SB-T Winter On-Peak $0.10723 $0.11523
Standby SB-T Winter Off-Peak $0.08943 $0.09743
Standby SB-T Winter Super-Off-Peak $0.04877 $0.05677
Standby S-TOU-S Summer On-Peak $0.20819 $0.21619
Standby S-TOU-S Summer Part-Peak $0.16658 $0.17458
Standby S-TOU-S Summer Off-Peak $0.11210 $0.12010
Standby S-TOU-S Winter Part-Peak $0.13101 $0.13901
Standby S-TOU-S Winter Off-Peak $0.17321 $0.18121
Standby S-TOU-P Summer On-Peak $0.20819 $0.21619

3CE Customer
Class Rate Schedule Time Period
Proposed
3CE
Choice
Proposed
3CE Prime
Standby S-TOU-P Summer Part-Peak $0.16658 $0.17458
Standby S-TOU-P Summer Off-Peak $0.11210 $0.12010
Standby S-TOU-P Winter Part-Peak $0.13101 $0.13901
Standby S-TOU-P Winter Off-Peak $0.17321 $0.18121
Standby S-TOU-T Summer On-Peak $0.13318 $0.14118
Standby S-TOU-T Summer Part-Peak $0.10448 $0.11248
Standby S-TOU-T Summer Off-Peak $0.06651 $0.07451
Standby S-TOU-T Winter Part-Peak $0.07983 $0.08783
Standby S-TOU-T Winter Off-Peak $0.10899 $0.11699
Lighting LS-3 (SCE) Year-Round All $0.07066 $0.07866
Lighting AL-2-F Year-Round All $0.07066 $0.07866
Lighting TC-1 (SCE) Year-Round All $0.09469 $0.10269
Lighting WTR Year-Round All $0.09469 $0.10269
Lighting LS-1 Year-Round All $0.11767 $0.12567
Lighting LS-3 (PG&E) Year-Round All $0.11767 $0.12567
Lighting TC-1 (PG&E) Year-Round All $0.12067 $0.12867