Policy Board of Directors
February 21, 2024
1:30 PM
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,
Fifth Floor Redwood Room
Santa Cruz, CA 95060
City of San Luis Obispo
City Hall
990 Palm Street, Council Chambers
San Luis Obispo, CA 93401
City of Santa Maria
City Hall
110 East Cook Street, Council Chambers
Santa Maria, CA 93454
City of Gonzales
City Hall
147 Fourth Street, Conference Room
Gonzales, CA 93926
Count of Santa Barbara
County Administration Building
105 E. 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/82977357049
Or join by phone:
+1 669 900 6833 or +1 669 219 2599
Enter this Webinar ID Number: 829 7735 7049 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/
AGENDA
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.
CONSENT CALENDAR
1. Approve minutes from the September 14, 2023 meeting of the Policy Board of Directors
2. Approve minutes from the December 13, 2023 meeting of the Policy Board of Directors
3. Adopt Resolution PB-2024-01 Setting the Regular Meeting Schedule of the Policy Board
4. Receive a Report on 3CE's Investment Returns and Diversification
5. Approve 3CE's Load Management Standards ("LMS") Plan and authorize the CEO to submit the LMS Plan to the California Energy Commission ("CEC") with subsequent updates as may be required by the CEC.
6. Receive Regulatory and Legislative Quarterly Update
7. Receive Update on FY 2023-24 Energy Programs
8. Receive a Financial Report for the periods October 1, 2023 and December 31, 2023
REGULAR AGENDA
9. CEO Report
a. Staffing update
b. Implementation date for City of Atascadero and County of San Luis Obispo Confirmed c. Front of the Meter Energy Storage program redesign
d. 3CE review of the Behind-the-Meter Energy Storage focused demand response proposals e. Expansion of system reliability pilots - AgFIT
f. Property acquisition
10. Receive a presentation on the challenges and impacts of the 2025 Compliance Year implementation of the 24-hour Slice of Day Resource Adequacy Paradigm
11. Adopt Resolution No. PB-2024-02 establishing a 3CE Net Billing Tariff (NBT), with an implementation date of June 1, 2024
12. Receive a Report on Efforts for Setting Rates Beginning FY 2024-25
13. Receive a Presentation 3CE’s FY 2022-23 Audited Financial Statements
14. Community Advisory Council Report
PRESENTATION
15. Receive the 2023 Annual Impact Report
CLOSED SESSION
16. Closed session under Government Code 54950 et. seq. relating to the following item:
Pursuant to Government Code section 54957(b), the Board will confer regarding evaluation of performance for the Chief Executive Officer.
a.
Adjournment
Policy Board of Directors
September 14, 2023
9:00 a.m.
Paso Robles Inn
1103 Spring Street Paso
Robles, CA 93446
MINUTES
The meeting was called to order at 9:00AM with 18 members present and a quorum established.
Directors Present: Adams, Baron, Brooks, Donaldson, Dutra, Freeman, Hamon, Kosmicki, Marx, McPherson, Nomura, Orona, Ortiz-Legg, Patino, Rios, Waage, Vice Chair Williams, Chair McShane Directors Absent: Keeley
Corrections or Additions
Clerk announced that there were no corrections or additions to the agenda.
The Chair opened the public comment period for the consent calendar and items not listed on the agenda.
No public comments received.
The Chair closed public comment period.
CONSENT CALENDAR
MOTION: Moved by Director Marx, seconded by Director Adams to approve the Consent Agenda.
ACTION: The Motion Carried with a roll call vote: 18/0/1 AYES: Adams, Baron, Brooks, Donaldson, Dutra, Freeman, Hamon, Kosmicki, Marx, McPherson, Nomura, Orona, Ortiz-Legg, Patino, Rios, Waage, Vice Chair Williams, Chair McShane NOES: None
ABSENT: Keeley
CONSENT CALENDAR
1. Approved minutes from the June 21, 2023 meeting of the Policy Board
2. Adopted Resolution No. PB-2023-06 approving Addendum No. 6 to the 3CE Community Choice Aggregation Implementation Plan and Statement of Intent and delegating authority to the CEO to file, if necessary, with the CPUC
3. Appointed Lew Bauman and Rosemary Soto to serve on the 3CE Community Advisory Council for a three (3) year term
4. Appointed Virginia Johnson and Kris Damhorst to serve on the 3CE Community Advisory Council for a three (3) year term
5. Appointed Matthew McClish to serve on the 3CE Community Advisory Council for a three (3) year term
6. Ratified reappointments of Community Advisory Councilmembers Heather Allen, Katie Davis, Wayne Norton, Richard Stedman, and Norman Tuitavuki to an additional three (3) year term; and reappointed Community Advisory Councilmembers Jeff Byron, Brandon O’Rourke, and Dennis Osmer to an additional three (3) year term
7. Approved 3CE Community Advisory Council FY 2023-24 work plan unanimously supported by the CAC
8. Received FY 2022-23 Energy Programs Update
9. Received Regulatory Quarterly Update
10. Received the Treasurer’s Report for the period October 1, 2022, through June 30, 2023
REGULAR AGENDA
11. Consider adopting the Fiscal Year 2023-24 Recommended Budget for Central Coast Community Energy (3CE) including updated Financial Policies; and adopt Resolution No. PB-2023-07 approving cost-based rate adjustments The Chair opened the public comment period for the consent calendar and items not listed on the agenda.
The following individual(s) addressed the board.
Seth Capron
John Smigelski
Michael Saint
The Chair closed public comment period.
MOTION: Moved by Director Waage, seconded by Director Dutra to approve.
ACTION: The Motion Carried with a voice vote: 18/0/1/0
AYES: Adams, Baron, Brooks, Donaldson, Dutra, Freeman, Hamon, Kosmicki, Marx, McPherson, Nomura, Orona, Ortiz-Legg, Patino, Rios, Waage, Vice Chair Williams, Chair McShane NOES: None
ABSENT: Keeley
ABSTAIN: None
12. Consider staff presentation and support proposal to reduce existing natural gas facility emissions while securing valuable Resource Adequacy product for CE through a hybrid natural gas power purchase agreement The Chair opened the public comment period.
The following individual(s) addressed the Board.
Seth Capron
The Chair closed public comment period.
MOTION: Moved by Director Ortiz-Legg, seconded by Director Waage to approve.
ACTION: The Motion Carried with a voice vote: 18/0/1/0
AYES: Adams, Baron, Brooks, Donaldson, Dutra, Freeman, Hamon, Kosmicki, Marx, McPherson, Nomura, Orona, Ortiz-Legg, Patino, Rios, Waage, Vice Chair Williams, Chair McShane NOES: None
ABSENT: Keeley
ABSTAIN: None
13. Receive Nominating Committee recommendation and appoint Das Williams as Policy Board Chair and Yvette Brooks as Vice Chair
The Chair opened the public comment period.
No public comments received.
The Chair closed public comment period.
MOTION: Moved by Director McPherson, seconded by Director Adams to approve.
ACTION: The Motion Carried with a voice vote: 18/0/1
AYES: Adams, Baron, Brooks, Donaldson, Dutra, Freeman, Hamon, Kosmicki, Marx, McPherson, Nomura, Orona, Ortiz-Legg, Patino, Rios, Waage, Vice Chair Williams, Chair McShane NOES: None
ABSENT: Keeley
Board member comments and reports
Adjournment
Policy Board of Directors
December 13, 2023
9:00AM
Central Coast Community Energy
70 Garden Court, Suite 300
Monterey, CA 93940
County of Santa Cruz
701 Ocean Street,
Fifth floor, Redwood Room
Santa Cruz, CA 95060
County of San Benito
550 Cagney Road
San Juan Bautista, CA 95045
City of San Luis Obispo
City Hall
990 Palm Street,
Council Chambers
San Luis Obispo, CA 93401
City of Santa Maria
City Hall
110 East Cook Street, Council Chambers Santa
Maria, CA 93454
City of Carpinteria
City Hall
5775 Carpinteria Ave
Carpinteria, CA 93013
MINUTES
The meeting was called to order at 9:10 AM with 15 members attending from 6 Noticed locations and a quorum established.
Directors Present:
3CE HQ: Adams, Baron, Delgado, Freeman, McShane
County of Santa Cruz: Dutra, McPherson, Vice Chair Brooks City of San Benito: Kosmicki
City of San Luis Obispo: Guthrie (arrived at 9:13am), Marx, Ortiz-Legg City of Santa Maria: Orona, Patino, Chair Williams
City of Carpinteria: Nomura
Directors Absent: Hamon, Keeley, Rios
Chair opened public comment period on closed session items.
There were no public comments.
Chair closed the public comment period.
Recessed into closed session at 9:10am
CLOSED SESSION
1. Closed session under Government Code 54956.8 - Conference with Real Property Negotiators PROPERTY: 1026 Palm, San Luis Obispo, CA
AGENCY NEGOTIATOR: Dewayne Woods
NEGOTIATING PARTIES: Palm Street Land Co, Gail Sinton Schoettler, Patricia Noel, Stephen Sinton, and Jane Sinton
UNDER NEGOTIATION: Price and Terms
Adjourned at 10:12am
Staff Report Item 3
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Heather Vowell, Board Clerk
SUBJECT: Adopt Resolution PB-2024-01 Setting the Regular Meeting Schedule of the Policy Board of Directors
DATE: 2/21/2024
RECOMMENDATION:
Adopt Resolution PB-2024-01 setting the regular meeting schedule of the Policy Board of Directors.
BACKGROUND:
Section 3.8 of the Central Coast Community Energy’s Joint Powers Agreement requires the Policy Board to hold up to three meetings per year, with the option for additional or special meetings as determined by the CEO and/or Chair, and that all meetings shall be conducted in accordance with the provisions of the Ralph M. Brown Act (the “Brown Act”). The Brown Act requires that the Policy Board provide a regular time and place for its meetings by resolution, ordinance, or other formal action.
The Policy Board has previously set their regularly scheduled meetings through adoption of Resolutions No. 1-2017; No. PB-2018-05; No. PB-2019-01; PB-2020-04. PB-2023-02 DISCUSSION/ANALYSIS:
Pending approval, regular meetings of the Policy Board will be held according to the following table:
February June September
Third (3rd ) Wednesday Third (3rd ) Wednesday* Third (3rd ) Thursday 1:30PM 1:30PM 9:00AM
*Meeting will move to the Fourth (4th ) Wednesday should the meeting fall on a holiday.
Staff recommendation maintains the Board’s current schedule but provides that when the third Wednesday falls on a holiday, the regular meeting will move to the fourth Wednesday.
FISCAL IMPACT:
No fiscal impact.
CONCLUSION:
The Policy Board’s adoption of Resolution PB-2024-01 enables the automatic reschedule of meetings that conflict with a holiday to ensure business continuity for the agency.
ATTACHMENT(S):
1. Draft Resolution PB-2024-01
DRAFT RESOLUTION NO. PB-2024-01
A RESOLUTION OF THE POLICY BOARD OF DIRECTORS OF THE CENTRAL COAST COMMUNITY ENERGY ESTABLISHING A REGULAR MEETING SCHEDULE; AND SUPERSEDING ALL
PREVIOUSLY ADOPTED RESOLUTIONS TO THE EXTENT OF ANY INCONSISTENT MEETING
SCHEDULE, LOCATION, AND TIMES
WHEREAS, the Central Coast Community Energy is a Joint Powers Authority established and operated pursuant to California Government Code section 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 Counties, and certain cities within San Luis Obispo County; and
WHEREAS, pursuant to the Ralph M. Brown Act, Government Code Section 54950 et seq and Section 3.8 of the Central Coast Community Energy Joint Powers Agreement, the Policy Board of Directors of the Authority ("Board") may fix, by resolution, the date upon which, and the hour and place at which, each regular meeting of the Board is to be held; and WHEREAS, the Authority desires to establish a regular meeting schedule by resolution and to supersede any prior resolutions related to the foregoing by this resolution; and NOW, THEREFORE, the POLICY Board of Directors of the Central Coast Community Energy does hereby resolve as follows:
1. The regular meetings of the Policy Board will be held according to the following table:
February June September
Location will rotate
between Headquarters
and southern territory
location as set by further
action of the Board and
indicated on a posted
agenda.
Location will rotate
between Headquarters
and southern territory
location as set by further
action of the Board and
indicated on a posted
agenda.
Location TBD in
conjunction with the Joint
Annual meeting and
indicated on a posted
agenda
Third (3rd) Wednesday Third (3rd) Wednesday* Second (2nd) Thursday 1:30 p.m. 1:30 p.m. 9:00 a.m.
* Meeting will move to the Fourth (4th) Wednesday should the meeting fall on a holiday
2. February 21, 2024, will be located at 70 Garden Court, Suite 300, Monterey, California, 93940.
3. The Policy Board’s September meeting will rotate between the northern and southern portions of the Authority’s service area and will be separately noticed in conjunction
with the Joint Annual Meeting.
4. If necessary, special Policy Board meetings will be convened and duly noticed as per Brown Act requirements. Pursuant to the Operations Rules and Procedures, the Clerk of the Board shall reserve and hold a December date for a special meeting, which will be convened if needed. Members are encouraged calendar this special meeting as soon as the Clerk provides notification of the December date.
5. Regular meetings may be cancelled by the Chair or CEO. This Resolution shall take effect immediately upon adoption.
PASSED AND ADOPTED by the Policy Board of the Central Coast Community Energy this by the following vote:
AYES:
NOES: None
ABSENT:
_____________________________
Chair, Das Williams
Attest:
_____________________________
Board Clerk, Heather Vowell
Staff Report Item 4
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Juan Lopez, Director of Finance
SUBJECT: Receive a Report on 3CE’s Investment Returns and Diversification DATE: February 21, 2024
RECOMMENDATION:
Receive a report on 3CE’s investment returns and diversification.
BACKGROUND:
The Audit and Finance Committee received an update on banking diversification on June 21, 2023, in response to the series of bank failures and bankruptcies that affected mid-size financial institutions in early 2023. Staff took guidance from the Committee to add additional financial and investment diversification to mitigate the potential risk of holding assets in a few concentrated financial institutions.
Since June 2023, staff have worked on diversifying 3CE’s cash and investment holdings while taking advantage of favorable interest rates to increase investment returns.
DISCUSSION/ANALYSIS:
Staff evaluated the fiscal position of 3CE’s current institutional banking and investment partners and found that they were appropriately collateralized and did not present an immediate risk. 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 not subject to the collateral requirement or FDIC coverage. 3CE monitors its risk exposure on an ongoing basis for those short-term investments. Although the funds held for operations are either FDIC-insured or collateralized, staff sought diversification efforts to minimize risks. Staff opened an operating account with JP Morgan Chase and two brokerage accounts with Schwab and Fidelity. Below is a breakdown of funds held as of January 31, 2024.
Investment Strategy
The Finance Department has spent the past months right sizing its portfolio to make its money work while keeping enough liquidity to meet operating costs. The investment strategy consists of holding three different “classes” of funds to right-size its portfolio:
cash to meet ongoing operation costs;
liquidity reserves to meet collateral calls and unforeseen costs; and core investment portfolio comprised of short-term investments.
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. Royal Bank of Canada (RBC) is the investment manager for $80.1 million of 3CE’s investments, while 3CE is the investment manager of the $30.2 million held in the Schwab brokerage account. 3CE has instructed RBC to let investments mature to free up liquidity reserves to ensure that deposits held from energy suppliers are readily available should they provide letters of credit to free up their collateral. An alternative option to using an investment manager or self-investing is to utilize a local government or state investment pool such as the Local Agency Investment Fund (LAIF) or California Asset Management Program (CAMP). 3CE researched these investment options and found the investment fees costly compared with self-investment, with little to no significant increased investment performance compared to 3CE’s current investment holdings because of a high-interest environment.
Investment Vehicles
3CE’s investment mix aligns with the Investment Policy and California Government Code. As of January 31, 2024, 3CE held $101.7 million in cash, $102.4 million in U.S. Treasuries, $40.2 million in certificates of deposit, $11.7 million in money market funds, and $4.5 million in federal agency notes. Aside from money market funds, all other investment types do not have state investment limits. State code limits money market funds to 20% of the portfolio and 3CE’s money market funds were at about 5%. All holdings managed by RBC and 3CE are high-grade rated investments or higher. Below is the breakdown of the cash and investment balances held by institution and investment mix as of January 31, 2024:
River City Bank $144,922,284
Chase 5,321,209
sub-total 150,243,494
Royal Bank of Canada $ 80,080,243
Schwab 30,230,860
sub-total 110,311,103
Total $260,554,597
Cash and Investment Balances
Operating Accounts
Investment Accounts Page 13 of 169
Investment Performance in a High-Interest Environment
The federal funds target rate has remained at 5.25% to 5.5% since last summer, following 11 increases that began in March 2022. After a long period of near-zero yields, yields on the three-month Treasury bill have been as high as 5.5%, their highest level since December 2000, per Morningstar. In Fiscal Year 2022- 23, 3CE put its cash to work in the various investment vehicles outlined in the prior section to take advantage of the high-interest environment. As a result, investment income totaled $8.2 million, an increase of $7.2 million from the prior fiscal year.
Of that $8.2 million, $3.5 million came from short-term investments in RBC and Schwab with monthly yields ranging from 2.3% to 6.1%, $2.5 million from money market funds and cash interest earnings held at River City Bank (RCB) with monthly yields ranging from 1.5% to 3.4%, and $2.1 million from certificates of deposits held at RCB with month yields ranging from 2.0% to 7.6%.
The first quarter of FY 2023-24 netted investment earnings of $3.0 million, made up of $1.3 million from short-term investments, $1.1 million from money market funds, and $0.6 million from certificates of deposits. 3CE anticipates seeing similar investment earnings in future quarters as long as the federal funds target rate remains consistent over the coming months.
FISCAL IMPACT:
There is no fiscal impact to receiving this report.
CONCLUSION:
Since its presentation to the Audit and Finance Committee on June 21, 2023, 3CE has been proactive in diversifying its financial institutional partners while putting cash and short-term investments to work to take advantage of a high-interest environment. This investment performance and diversification will right-size the portfolio to meet short and long-term obligations while mitigating investment risks. This report was presented to the Audit & Finance Committee on February 21, 2024.
ATTACHMENT(S):
None.
Institution Balance Investment Mix
River City Bank $144,922,284
Cash (sweep) - $89M
CDs - $40M
Money Market - $10M
cash (operating) - $5M
Chase 5,321,209 cash (operating)
Royal Bank of Canada 80,080,243
Treasuries - $74M
Federal Agencies - $5M
Money Market - $1M
Schwab 30,230,860
Treasuries - $28M
cash (sweep) - $2M
Total $260,554,597
Staff Report Item 5
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Jerri Strickland, Policy Advisor
SUBJECT: Approve 3CE’s Load Management Standards (“LMS”) Plan and authorize the CEO to submit the LMS Plan to the California Energy Commission (“CEC”) with subsequent updates as may be required by the CEC.
DATE: February 21, 2024
RECOMMENDATION:
This memorandum recommends the Policy Board approve 3CE’s Load Management Standards (“LMS”) Plan and authorize the CEO to submit the LMS Plan to the California Energy Commission (“CEC”) with subsequent updates as may be required by the CEC.
BACKGROUND:
California Code of Regulations, Public Utility Sector, Section §1623.1(a)(1) requires CCA to develop and submit no later than April 1, 2024, an LMS Plan approved by their governing board.
The CEC established Load Management Standards for all load serving entities in California to support development of demand flexibility and contribute to the state’s climate policy goals.
The CEC’s primary objective of the Load Management Standards encompass:
1. Ensuring the accuracy of existing and future time-varying rates in the Market Informed Demand Automation Server (MIDAS) rate database, which is publicly accessible and machine-readable.
2. Developing a standard rate information access tool to support third-party Demand Response and Load Management services.
3. Creating and submitting location marginal price-based rates that change at least hourly to reflect marginal wholesale costs.
4. Integrating information about new time-varying rates and automation technologies into existing customer education and outreach programs.
DISCUSSION:
3CE’s LMS Plan describes the framework 3CE will consider energy programs and/or rate structures that encourage 3CE customers to use electrical energy at off-peak hours, encourage the control of daily and seasonal peak loads to improve electric system efficiency and reliability, lessening or delaying the need for new electrical capacity, or reducing fossil fuel consumption and greenhouse gas emissions.
In 3CE’s Plan, different pathways of meeting the CEC’s goals are identified, including consideration of our own unique marginal cost rate offering, which would integrate real-time market data to send a price signal to the customer allowing them to adjust their consumption pattern. 3CE will evaluate all potential programs or rate offerings for cost-effectiveness, equity, technological feasibility, and benefits to customers and the grid.
3CE will also consider partnership opportunities with IOUs on new or already successful CPUC-approved programs, such as the recently adopted Agricultural Flexible Irrigation Tarriff (“AgFIT”) program. AgFIT is aimed to help farms manage costs by adjusting their irrigation plans based on real time signals of pumping and irrigation costs.
3CE will be making subsequent filings, in accordance with California Code of Regulations, Public Utility Sector, Section §1623.1, as per the standards outlined by the CEC’s LMS. By July 1, 2025, 3CE is tasked with the implementation of at least one marginal cost-based rate to remain consistent with the objectives of the LMS. To fulfill this goal, 3CE intends to collaborate with PG&E on the deployment of the AgFIT program. Updates on the development of specific programs and rates will be provided to this Board.
FISCAL IMPACT:
There is no fiscal impact to this action.
CONCLUSION:
The Board’s approval of 3CE’s LMS Plan allows 3CE to meet the required timeline for submitting a plan to the CEC and begin the technical assessment necessary to determine the feasibility of real time rate offerings.
ATTACHMENT(S):
3CE’s Load Management Standards Plan
2024
Load Management Standards
CENTRAL COAST COMMUNITY ENERGY
1 Table of Contents
Introduction ..................................................................................................................................................2 About 3CE: ................................................................................................................................................ 2 3CE’s Boards:......................................................................................................................................... 2 The CEC’s Load Management Standards: ................................................................................................. 3 3CE’s Plan for Marginal Rate Development:.................................................................................................5 Rate Design & Deployment....................................................................................................................... 5 Marginal Rate Design Timeline ............................................................................................................. 8 Cost effectiveness: ................................................................................................................................ 9 Equity: ................................................................................................................................................. 10 Technologically Feasible: .................................................................................................................... 11 Beneficial to Customers and the Grid................................................................................................. 12 Resources to Create Marginal Rate Design......................................................................................... 13 Rate Deployment Timeline ................................................................................................................. 14 Anticipated Resources for Rate Deployment...................................................................................... 14 Internal infrastructure for Marginal Cost Rates Adoption.................................................................. 14 Time Dependent rate submission to MIDAS via MIDAS Application Programming Interface (API)....... 15 Status of MIDAS submissions for current time-dependent rates....................................................... 15 Composite rate calculation and submission solution ......................................................................... 15 Plan for ensuring accuracy and maintenance of current time-dependent rates ............................... 15 Internal infrastructure progress/upgrades for LMS-complaint submission to MIDAS....................... 16 Plan to provide RIN(s) on customer billing statements. ......................................................................... 16 Implementation plan with timeline:................................................................................................... 16 Billing system updates ........................................................................................................................ 16 Proposed text design and QR code design and proposed placement on billing statements............. 16 QR code linked webpage and design:................................................................................................. 17 Plans and current participation in the development of Single Statewide RIN Access Tool.................... 17 List of cost-effective LMS-compliant programs and rates...................................................................... 17 Hourly-MIDAS signals-based load flexibility programs:...................................................................... 17 Additional Information Regarding Marginal Cost Rates & Programs................................................. 19 Public Information Program on Marginal Cost Rates/Programs............................................................ 20 Conclusion...................................................................................................................................................20 Attachment A: MIDAS Rate Imports...........................................................................................................22
2 Introduction
This plan highlights how Central Coast Community Energy’s (3CE) Boards’ decisions align with the California Energy Commission (CEC) goals by meeting or exceeding the timeline of their Load Management Standards (LMS). The strategies outlined in this plan are to be evaluated and implemented by 3CE staff at our board's direction.
About 3CE:
Central Coast Community Energy (3CE) is a public agency that sources competitively priced electricity from clean and renewable energy resources. Through its dedicated Boards and professional staff, 3CE is committed to reducing greenhouse gas emissions by accelerating the transition to 100% clean and renewable energy, while maintaining competitive rates. 3CE is committed to address the effects of climate change by investing in the development of a renewable and reliable grid that supports the electrification of sectors such as transportation, agriculture, and buildings—and incentivizing that change through innovative and impactful energy programs. 3CE is an A-credit rated public electric generation provider comprised of 35 municipal jurisdictions across five counties. With two jurisdictions remaining to enroll, 3CE currently serves over 1 million people through nearly 450,000 customer accounts representing approximately 95% of the region’s electricity load. 3CE has a peak retail load of 5,200MW and provides roughly 5 million MWh of power to its customers annually. 3CE promotes long-term electric rate stability and energy security while reducing reliance on fossil fuels and stimulating our local economies. 3CE’s Boards:
3CE's Policy and Operations Boards, comprising 19 seats each, represent 35 member agencies.
The Policy Board directs the strategic vision, budget, rates, and major non-power-procurement capital expenses, while the Operations Board oversees contracts and policies to ensure effective administration.
3CE’s Boards have actively engaged in responsible fulfillment of state climate policies, resulting in:
1. Procurement Strategy: Commitment to serving 100% of retail sales with incremental clean and renewable energy by 2030, with a stretch goal of balancing monthly.
2. Resource Adequacy Hedging: Support for a structured approach ensuring system reliability through various measures, including investment in energy storage, baseload renewable energy technologies, and demand response.
3. Ratemaking Discretion: Utilizing the Policy Board’s ratemaking discretion to adopt rates based on the cost to serve customers, supporting competitive and stable generation rates in line with state climate policies.
4. Local and Targeted Hire Procurement Policy: Establishment of a policy to prioritize local and targeted hiring in procurement processes.
3 The CEC’s Load Management Standards:
The Warren-Alquist Act of 1974 established the California Energy Commission (CEC) and granted the CEC specific authority, including the ability to review and approve the siting of power plants, set efficiency standards for buildings and appliances, and establish load management standards. In 2022, the Load Management Standards (LMS) underwent updates with amendments aimed at enhancing statewide demand flexibility in order to support California’s climate policies and the aggressive adoption of renewable energy generation technologies.
1 These revised standards are applicable to major entities such as large investor-owned utilities, large publicly owned utilities, and twelve large Community Choice Aggregators (CCAs), like 3CE, providing over 700GWh of electricity annually.
One important factor identified by the LMS in supporting demand flexibility and the state’s climate policies is the principle of marginal-cost based rates. Marginal-cost based rates, commonly linked to the wholesale price of electricity, are determined by factors like fuel costs, operational expenses, and the total demand for electricity at a specific time. These rates fluctuate during the day, adapting to shifts in demand and the accessibility of diverse energy sources.
The CEC’s primary objectives of the Load Management Standards encompass:
1. Ensuring the accuracy of existing and future time-varying rates in the Market Informed Demand Automation Server (MIDAS) rate database, which is publicly accessible and machine-readable.
2. Developing a standard rate information access tool to support third-party Demand Response and Load Management services.
3. Creating and submitting location marginal price-based rates that change at least hourly to reflect marginal wholesale costs.
4. Integrating information about new time-varying rates and automation technologies into existing customer education and outreach programs.2
To do this, the LMS outlines different goals and timelines for the large CCAs, POUs and IOUs to meet all four of the primary objectives. A notable difference for CCAs is that the LMS allows CCAs to either create their own rates or programs or participate in already existing IOU programs and rate offerings, with their governing board’s approval. The following sections of this document elaborate how 3CE plans to meet or surpass these objectives, outlining the board-approved plan concerning the main goals and other goals stipulated by the CEC Load Management Standards. 1 California Energy Commission. "Load Management Fact Sheet." Accessed February 2024. https://www.energy.ca.gov/sites/default/files/2022-10/Load_Management_Fact_Sheet_ADA.pdf 2 California Energy Commission. "Load Management Standards." Accessed February 2024. https://www.energy.ca.gov/programs-and-topics/topics/load-flexibility/load-management-standards
4 Table 1: LMS Standards and Goal Date
Load Management Standard Description LMS Goal Date Status §1623.1(c) Within three months of LMS
effective date, upload existing
time-dependent rates to the
MIDAS database
1-Jul-23 Achieved
(Ahead of goal date.)
§1623.1(a)(1) Within one year of LMS effective
date, develop and submit a plan
addressing how 3CE intends to
meet the objectives of the CEC
LMS, including the evaluation of
marginal cost-based rates and
programs, to 3CE’s Board. The plan
must be considered for adoption
within 60 days after submission.
1-Apr-23 Achieved
(Ahead of goal date.)
§1623.1(a)(3)(A) Submit a plan to CEC within 30
days of adoption of the plan.
Respond to requests for additional
information and/or
recommendations with 90 days.
30 days after
3CE board vote
In progress
§1623(c) Within one year of LMS effective
date, provide customers access to
their Rate Identification Numbers
(RIN) on billing statements and in
online accounts using both text
and QR
31-Mar-24 In progress
§1623(c) Within 18 months of LMS effective
date, develop and submit to the
CEC, in conjunction with the other
obligated utilities, a single
statewide standard tool for
authorized rate data access by
third parties, and the terms and
conditions for using the tool. Upon
CEC approval, maintain and
implement the tool.
1-Oct-24 In progress
§1623.1(b)(3) Within 18 months of LMS effective
date, submit to the CEC a list of
load flexibility programs deemed
cost effective by 3CE. The portfolio
of programs must provide at least
one option to automate response
to MIDAS signals for each customer
class where 3CE’s Board has
determined such a program would
materially reduce peak demand.
2-Oct-24 In progress
5 §1623.1(a)(3)(C) Submit annual reports to the CEC
demonstrating implementation of
plan, as approved by the Board
Annually Ongoing
§1623.1(b)(2) Within twenty-seven months of
the LMS effective date, submit at
least one marginal cost-based rate
or program to Board for approval
for any customer class(es) where
such a rate will materially reduce
peak load. An Information copy of
the tariff applications will be
provided to the CEC.
1-Jul-25 In progress
§1623.1(b)(2) Within fifty-one months of the LMS
effective date, offer each customer
voluntary participation in either a
marginal cost-based rate, if
approved by the Board, or a cost-effective load flexibility program. 1-Jul-27 In progress
§1623.1(b)(5) Conduct a public information
program to inform and educate
affected customers why marginal
cost-based rates or load flexibility
programs and automation are
needed, how they will be used, and
how these rates and programs can
save customers money.
No Goal Date
Specified
Dependent upon
3CE board direction,
to be done in
coordination with
Marginal Rate or
Program
Deployment.
§1623.1(a)(1)(C) Review the plan at least once every
3 years after the plan is adopted
and submit a plan update to the
Board if there is a material change.
Triennially Ongoing
3CE’s Plan for Marginal Rate Development:
Rate Design & Deployment
Community Choice Aggregators (CCAs) governing boards have jurisdictional control over rate setting on behalf of their customers. Public Utilities Code Section 366.2(c)(3) provides that that CCAs retain jurisdiction for setting rates for the electricity they purchase on behalf of their communities. This local control empowers CCAs to tailor energy programs, determine pricing structures, and prioritize renewable energy sources according to the preferences and goals of the communities they serve. 3CE sets rates locally through a transparent process involving community stakeholders and board members representing each community 3CE serves. Local rate-setting reflects our region’s coastal and inland climates, the unique energy needs of our diverse Central Coast community and allows for input from customers and communities served.
6 3CE also conducts rigorous data driven analysis prior to presenting options to the Policy Board and community stakeholders prior to rate adoption. Quantitative studies are conducted to ensure that rates are fair, equitable, and competitive while recovering necessary costs. One way 3CE does this is by designing rates using a cost-of-service rate structure. The cost-based rate structure allows for simple, stable rates that support 3CE’s commitments to customer benefits, community investment, and the growth of clean and renewable energy.
When proposing either participation in a dynamic pricing program or customer rate option, 3CE will ensure that charges to the customer follow these same principles. 3CE will only seek Board approval for time dependent rates after such rates have been proven to be cost effective, equitable, technologically feasible, and beneficial to customers and the grid. This could result in an array of marginal rates for all customers, or fewer for more niche customer classes that are proven cost effective.
The CEC LMS requests the Large CCA’s to present at least one marginal cost-based rate to their Boards by July 1, 2025 and to offer customers voluntary participation, if approved by the Board, by June 30, 2027. 3CE has already begun investigating various pathways that achieve these timelines, such as the IOU partnered programs Expanded AgFIT and the SCE Dynamic Rate Pilots that were recently approved for expansion to CCAs by the CPUC in the Demand Flexibility proceeding (R.22-07-005). 3 These pilots
could be fruitful opportunities to test viability, establish best practices for customer support, and gain experience with differing programmatic designs for real time pricing.
As 3CE considers potential marginal rates and program options, distinct deployment timelines emerge dependent upon joining an existing pilot or independently testing marginal rates and program concepts. Depending upon CPUC decision in the current Demand Flexibility proceeding, the PG&E Expanded AgFIT pilot and SCE Demand Flex Pilot could be available for CCA participation as soon as June 2024. With the quickly approaching opportunities and limited meetings of the policy board in in conjunction to those timelines, the first step of instituting this LMS Plan will be for the board to approve and authorize the CEO to submit this plan to the CEC, in a form that is substantially similar to what is outlined herein, as well as any subsequent updates which align with the written CEC LMS. The board will still have the ultimate authority, but the designation to the CEO will allow 3CE to meet all LMS timelines and potential opportunities without delay due to the cadence of board meetings. 3CE will consider all available options; however, if IOU programs are not equitably designed for both bundled and unbundled customer participation, 3CE may consider the creation of its own independent marginal rate pilot. This would be brought back to the board for approvals. In the next section, 3CE considers its options for Marginal Rate Design if were not to participate in an existing IOU rate or pilot. 3 California Public Utilities Commission. D.24-01-032. Accessed February 2024. https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M524/K176/524176497.PDF.
7 Table 2: Goals Met or Progressed by Participating in Existing IOU Programs CPUC
Approved
Programs
Load Management
Standards
LMS
Goal
Date
Potential
Program
Start Date
1. PG&E
Expanded AgFIT
Pilot Program
2. PG&E
Expanded Pilot
Two
§1623.1(b)(3):
Submit to the CEC a list of load flexibility programs
deemed cost effective. At least one option to automate
response to MIDAS signals for each customer class
where 3CE’s Board has determined it would materially
reduce peak demand.
*Both pilot opportunities could allow customers to
respond to MIDAS signals to shift their energy usage to times where energy is less expensive.
2-Oct-24
1-Jun-24
3. SCE Dynamic
Rate Pilot 1-Jun-24
1. PG&E
Expanded AgFIT
Pilot Program
2. PG&E
Expanded Pilot
Two
§1623.1(b)(2):
Submit at least one marginal cost-based program to
Board for approval for any customer class where such a
rate will materially reduce peak load.
*Rates utilized for these pilot programs utilize pre-approved CPUC rate formulas. Board approval to participate would also be consenting to utilizing the IOU formulas.
1-Jul-25
1-Jun-24
3. SCE Dynamic
Rate Pilot 1-Jun-24
1. PG&E
Expanded AgFIT
Pilot Program
2. PG&E
Expanded Pilot
Two
§1623.1(b)(2)
Offer Customers voluntary participation in either a
marginal cost-based rate, or cost-effective load flexibility program.
*Participating in either pilot would create a voluntary participation opportunities in a load flexibility program for 3CE customers.
1-Jul-27
1-Jun-24
3. SCE Dynamic
Rate Pilot 1-Jun-24
8 Marginal Rate Design Timeline
Section 1623.1(b)(2) of the LMS requests the Large CCAs to seek approval from their Boards for at least one dynamic rate or cost-effective program for which its rate-approving body determines such rate will materially reduce peak load. The application must be submitted within twenty-seven months of the updated LMS effective date, or by July 1, 2025. The rate offered, if desired, can mirror the IOUs in whose service area the Large CCA exists. Rates or programs would be approved by the CCA’s board and expanded to all customer classes that are deemed cost-effective and would reduce peak load, by July 1, 2027, in accordance with section 1623.1(b)(4).
3CE will weigh the potential of offering a program or a rate option to its customers. For either path, if 3CE were to do so independently from an IOU partnered program or rate, 3CE would need to explore the development of its own Marginal Rate Design. Calpine Energy Solutions (Calpine) is 3CE’s contracted back-office provider who fulfills this function and would assist in accomplishing the work referenced throughout this section.
Independently creating a Marginal Rate Design would require setting up or subscribing to a real-time or day-ahead index sourcing data from CAISO markets and integrating it into the back-office provider’s billing system. 3CE,Calpine, and potentially a rate design consultant, would develop the customized rate design to layer on top of the pricing signals coming from the index. Receiving interval data at the appropriate increment level would be crucial for this program or rate.
Depending on how the IOUs make interval data available to the CCAs, the Calpine would have to develop internal infrastructure to accept and provide quality assessments of new data streams coming from both SCE and PG&E. Due to current energy meter capabilities, technological shortfalls, or delayed timeliness of receiving data from the IOUs, it is inevitable that interval data will not be available for some customers some of the time. For those cases, 3CE and Calpine, would need to consider how to design a hierarchy of data to be substituted from other available sources. Any new program of this nature would require custom process controls to ensure accuracy and timeliness and custom reporting would have to be designed, built and maintained.
The LMS and CEC guidance states that rates must be shown to be (1) cost-effective, (2) equitable, (3) technologically feasible, and (4) beneficial to customers and the grid. 3CE would need to evaluate these factors along with its own standards of equitable and stable rate design if it elected to develop marginal rates and track them over time. The LMS requests that a single marginal rate be proposed to our board by April 1, 2025. The following sections outline 3CE’s initial assessment of the four LMS rate criteria.
9 Image 1: Flowchart for LMS Rate or Program Approval Process Cost effectiveness:
To evaluate the cost-effectiveness of Marginal Rate Designs and related programs at 3CE, both costs and benefits must be considered with the initial program and monitored over time as it matures. 3CE will consider the development of a framework or formula identifying and quantifying the cost-effectiveness. Demand side management cost effectiveness tests are widely accepted and offer a general guideline or reference to developing a quantification of the cost and benefit for Marginal Rate Designs for 3CE and its customers. In California, the CPUC references these common cost-benefit tests for use in evaluating energy efficiency, demand response, and distributed energy resource program selections and justification. Some tests 3CE could utilize to evaluate cost-effectiveness include the Total Resource Cost (TRC), Ratepayer Impact Measure (RIM), Program Administration (PA), and Participant (PCT) Tests. Each of these Tests generally evaluates the costs of the program or measure from the utility and/or customer point of view and the benefits in reduced bills for customers or costs for utilities.
To support the cost-effective evaluation of the marginal rate program and rates, 3CE will need to evaluate developing a calculation based on the TRC for energy efficiency measures. A simplified TRC calculation is a ratio of total benefits divided by total costs. If the TRC calculation is greater than 1.0, it means the total benefits outweigh the total costs. This could be performed by 3CE on a class-by-class basis for the marginal rate program to better inform performance and program related decisions. It could also consider societal benefit elements; however, they may be secondary qualitative benefits rather than quantified within the ratio of benefits to costs.
Components and elements to use in the cost-effectiveness calculation could include:
Costs to 3CE:
Program administration, staff time, applicable pilot programs, any customer information system or Calpine costs, etc.
The CEC LMS requests
large CCAs to seek board
approval for a marginal
cost rate that materially
reduces peak load.
3CE must evaluate rate or
program options for:
1. Cost effective;
2. Equitable;
3. Technologically Feasible;
4. Beneficial to Customers and
the Grid.
Receive Board Approval
by July 1, 2025
If proposed rate does not
satisfactorily meet the four
criteria, the Board may
oppose.
3CE’s board may also
designate authority to the
CEO to evaluate joining
IOU programs LMS.
3CE may join an IOU CPUC
approved program or offer
an IOU CPUC approved
marginal rate.
10 Customer incentives or rebates paid to participants to offset costs of a third party, new behind the meter device, or new technology application
Benefits to 3CE and its Customers:
Avoided energy and capacity/resource adequacy costs including incremental reserve margin considerations
Environmental or GHG reductions
Other societal benefits, if desired and quantifiable; if not quantified, could be qualitative and considered in evaluation
The CPUC Avoided Cost Calculator (ACC) could also be used to standardize the benefits of avoided energy, capacity, and GHG costs
Potential Metrics:
Marginal rate benefit to cost ratio for customer classes (a ratio of greater than 1.0 represents the benefits outweighing the costs)
Other societal or qualitative benefit considerations
Equity:
Equity for Marginal Rate Designs should focus on two items: 1) the equity in the actual rate making and design of the rate to avoid cost shifting and 2) equitable customer access to and benefits from the program. Equity in rate making is a fundamental principle and goal in regulatory and utility economics. Equity in reference to rate making is often linked to cost of service (COS) results which document and develop rates that are based on each customer class’s costs imposed on the system to provide electric service. Comparing the customer class’s COS and existing rate revenues identify potential subsidization issues from one or more customer classes to others. To avoid potential subsidies, COS-based rates are typically used as the basis for rate making. Thus, for equitable marginal rates in each class, a COS study or similar cost-based quantification with marginal costs for the marginal rates should be utilized.
Addressing equity is an important factor for 3CE. 3CE has an Underserved Communities Outreach and Engagement Plan that will be utilized to identify communities that have the potential to benefit most from possible cost savings of a marginal cost rates. The Engagement Plan also outlines the networks to collaborate with to engage most effectively with those communities.
To monitor and evaluate broader equity in customer participation for the program, 3CE would consider the development of various goals, targets, and even metrics to report on and guide strategy for the implementation of the marginal rate and plan across customer classes. With the implementation of complicated marginal rates which require a third party and application of new technologies, certain customer classes and customer segments within classes could be underserved unless thoughtful attention is made to ensure their enrollment and continued success. Residential and small commercial customer classes are likely to be less prepared to take advantage of marginal rate or program opportunities than larger, commercial and industrial customers with experience in these areas. To ensure equitable access to the marginal rate benefits or programs, especially in penetrating the residential and small commercial customer classes, 3CE may need to consider developing additional incentive programs to support adoption in these “hard to reach” or low-income and small businesses
11 customer segments. These incentives would be designed to increase the adoption rates of the Plan and support the equitable availability and benefits of the marginal rates.
Possible metrics and goals 3CE will consider:
• Residential Customer Class:
o Number of disadvantaged residential customers identified by 3CE load research that would benefit from marginal rates and were contacted to participate in incentives and the program.
o Percent of total disadvantaged residential customers adopting marginal rates • Small Commercial Class:
o Number of local, small, or diverse business customers identified by 3CE load research that would benefit from marginal rate or program and were contacted to participate in incentives and the program.
o Percent of total local, small, or diverse businesses adopting marginal rates Technologically Feasible:
The third factor for evaluating the Marginal Rate Design and program is technological feasibility. 3CE would need to evaluate the rate design implementation for internal, customer, external-third-party technologies needed to utilize and take advantage of the new marginal rates.
Internal 3CE Technology Feasibility
The creation of a Marginal rate, if 3CE’s board chooses to move forward with the design and implementation, is technologically feasible. All data required to design the cost-based rates is currently available via energy market data sources and 3CE’s own customer usage data. As the Load Serving Entity (LSE) marginal rates will be focused on power supply costs, all load profile data, hourly energy consumption, and class contributions to system peak demands are already known and available.
Furthermore, 3CE and many CCAs have years of experience collaborating with, integrating, and utilizing IOU data sets including billing determinant data, charges and rate structures, and load profiles.
If 3CE’s board chooses to implement and support the ongoing operation of a marginal rate or program, it will require additional technology or programming support to implement enhanced analysis and evaluation of marginal rates and programs. As a part of the implementation 3CE data analytics would need to augment resources with a combination of external vendor support or internal up-scaling of staff. This could include investments in software, analysis, or machine learning to support the identification of specific customers or load profiles that would benefit from marginal rates. This type of additional effort and investment could support targeted marketing and increased beneficial participation in the program over time.
Customer Technology Feasibility
Availability of customer technology that can gather, understand, and take advantage of marginal rate pricing signals and opportunities is a critical success factor for these rates. One of the key data inventories and technology systems customers must interface with to take advantage of these opportunities is the CEC’s Market Informed Demand Automation Server (MIDAS). MIDAS is intended to house an up-to-date inventory of utility rates for participating California electric utilities. For customers
12 to participate in the marginal rate program, they must team with a third party or create their own Application Programming Interface (API) connection to MIDAS to continually receive the RTP rates required to make consumption related decisions. It is common for existing energy service companies to already have APIs set up to receive information from the local IOU on behalf of their customers or participants in utility programs. As energy service companies typically target and cater to large business and industrial customers, it is expected these classes will have early access to the RTP rates and enable the implementation in those classes. Further expansions of third parties or energy service companies into the small commercial and residential customer classes may lag behind the larger commercial and industrial customer classes.
There are customer-facing technologies that are currently, or will in the near future, have capabilities to interpret and enable actions based on the marginal rate pricing signals. These are likely to include current or expected two-way communication technologies and equipment such as EV charging, smart thermostats, battery storage, building control systems, and other energy efficiency programs or technologies currently in place. These existing customer technologies and equipment span residential to industrial customers. Thus, 3CE should be open to marginal rate program penetration in all customer classes and segments. While there are no specific metrics or key performance indicators initially identified in the technologically feasible factor, 3CE will continue to monitor customer enabling technologies, programs, or equipment available in each customer class to ensure opportunities in each customer class.
Potential Metrics for Customer Technology Feasibility:
3CE could internally identify customers that would benefit from marginal rates or track the number of third-party technology providers serving each customer class.
Beneficial to Customers and the Grid
If 3CE were to design a marginal rate or program it would need to support benefits for both the customers and grid. One way of doing so is using cost-based principles within the rate design. This provides an impartial view of the costs and benefits which allows customers and related enabling technologies to make choices on the economics and then shift or change consumption patterns. Below is a summary of the customer and grid-related benefits.
Customer Benefits
Customer benefits could potentially include reduced bills if optimized and properly managed by the customer or third-party technology. A reduction demand should result in lower costs for all customers during peak hours. While marginal rates provide opportunities for reduced costs and bills, there is also the potential for increased risks related to volatile market prices. Customers must manage these market pricing risks or have a way to mitigate them during large pricing fluctuations, seasonal shifts, or weather events. To address the large potential pricing fluctuations in the market, 3CE could consider an additional fee, subscription model, or fixed change related to the marginal rate or program for customers. This added rate component would act to support a pricing mitigation or hedging program on behalf of customers to limit customer’s exposure to large swings in prices or weather events. 3CE could consider offering this program or allowing the market and third parties to develop a pricing exposure or hedging service for customers.
13 Grid Benefits
Grid related benefits are assumed to be shared or passed through to customers. These financial benefits are directly linked to the marginal rate and cost-basis which include avoided future generation capacity or resource adequacy costs and avoided energy purchases. There may also be reduced GHG compliance costs which would also benefit the utility and grid. Broader non-economic benefits would include reduced GHG emissions.
Potential Metrics for Grid Benefit:
Reduced customer bills
Reduced utility energy and resource adequacy costs
Reduced GHG compliance costs
Reduced GHG emissions
Resources to Create Marginal Rate Design
The examination of marginal rate design and potential programs has already incurred costs, utilized staff time, and consumed resources. To create a Marginal Rate that consider the four criteria described in the previous section, 3CE would need to hire a Rate Design Consultant to assist in the evaluation. The final rate designed by the consultant would then need to be presented to the board for approval.
Resources and efforts that have already been spent:
In the development of this plan, 3CE has already dedicated the following efforts:
o Time to create an RFP for a Rate Design Consultant.
o Cost of Rate Design consultant to consider variables and initial evaluation of LMS requirements.
o Analysis from back-office providers on needs for billing and customer performance evaluation of marginal rates.
o 3CE staff time to
Participation in CEC LMS Working Groups.
Conduct vendor negotiations and contract development for consultants. Produce the of LMS Plan and present it to their board Future Resources and Efforts Estimation:
Based on our initial assessment, we have determined that while aspects of future creation of marginal rates are feasible, the overall effort needed for a final product will be significant and require contracting with an external rate design consultant.
3CE Staff Needs:
Finance and Rates staff representative(s) to support marginal rate development, cost research and analysis and rate making.
Customer Engagement or Customer Programs staff and leadership to support stakeholder engagement and development of the incentives and overall Plan.
14 IT and Data Warehouse staff to support data queries, machine learning efforts and analysis of customer and system loads.
Rate Design Consultant Needs:
Rate Design Consultant contract and staff to support and develop marginal rates. Ongoing support and evaluation of 3CE’s LMS Plan, potential research topics and data analytics.
Rate Deployment Timeline
Once a rate or program is designed and tested, the logical progression to contemplate is the deployment of the rate and customer enrollment. Section §1623.1(b)(2) requests that the Large CCAs offer customers voluntary participation in either a marginal cost-based rate, if approved by the Board, or a cost-effective load flexibility program by July 1, 2027. The timeline of deployment is dependent upon whether 3CE’s board elects to adopt a Marginal rate that mirrors the IOUs by participating in a CPUC approved program or chooses to design its own rate or program. The board will make their assessment based upon the lessons learned from potential pilot participation, rate consultant insights, and staff recommendations.
Anticipated Resources for Rate Deployment
To deploy a marginal rate 3CE would need to complete its design and seek approval from the Policy Board. If staff were directed to do deploy the rate, this would require both internal infrastructure and staff to support customer outreach. The exact requirements would be based upon final program design and targeted customers.
Although not exhaustive and subject to change, 3CE anticipates that the following resources would be needed to successfully deploy a new marginal rate in its service area:
- Internal rate education by rate design consultant.
- Full Outreach Campaign Design & Budget
o Defined goals and outreach strategy
o Clear messaging for targeted audience
o Additional warm-up campaigns for historically hard-to-reach customers - Website development
- Call Center Training
- Customer Marketing & Education on the rate opportunity:
- Design Marketing Collateral
- Informational Webinars
- 1:1 Contact with enrolling customers
- 1:1 Ongoing Contact throughout enrolled customers participation - Email, Direct Mail, Social & Digital campaigns
Internal infrastructure for Marginal Cost Rates Adoption Upgrades to 3CE’s internal infrastructure and back-office provider capabilities are anticipated if marginal rates are adopted. Although not an exhaustive list, below are anticipated areas where staff and contracted vendors will need to consider upgrades:
15 Billing system compatibility review and improvement plan and resource commitment:
Implementing a marginal rate in general or more specifically an expansion of the AgFIT program, would require a significant investment in billing engine infrastructure upgrades and staff training for 3CE’s back office-provider, Calpine Energy Solutions. In order to train existing staff and potentially bring on new team members to support these innovative rate structures, Calpine, would set weekly meetings to ensure a comprehensive understanding of the regular requirements to support those rates. Weekly meetings to design the program including the billing system, controls, processes and reporting would also be expected.
A significant component of the work to support marginal rates would go into developing the new rate sheets. New hourly rate sheet will need to be designed, tested, and their cadence determined.
This may require daily price updates, depending on program structure.
In order to appropriately bill customers on any form of marginal rate, 3CE and their back-office provider, Calpine, would need to receive the appropriate interval usage data from PG&E for participating customers. Calpine would be expected to implement this process, new controls and reporting would be needed, as well as updates to the internal customer information system and contact center talking points for external communication. A significant amount of staff time would be allocated to monitoring the new systems in place to support the marginal rate or program. This work would also be determinant upon the size of the customer segment targeted for participation and different needs for that customer type, whether they are residential, commercial, or agricultural. 3CE would also need to work with a Rate Design Consultant to ensure an hourly marginal costs-based rates calculation system was developed. This would require upgrades to the current billing system functionality. Due to the necessary upgrades and additional services required for marginal rate implementation, 3CE anticipates that it would need to be able to cover increased costs on data storage, data transfer, legal review, staff time, and more.
Time Dependent rate submission to MIDAS via MIDAS Application Programming Interface (API)
Status of MIDAS submissions for current time-dependent rates 3CE has successfully uploaded all generation rates and associated RIN’s to the CEC’s MIDAS server. 3CE has a total of 588 rates uploaded into MIDAS including base rates and rates with price adders spanning both their PGE and SCE territory combined. 3CE will continue to upload our generation rate components.
A comprehensive list of the rates 3CE has uploaded to MIDAS is included as Attachment A. .
Composite rate calculation and submission solution
3CE will continue to input our generation rates into MIDAS and will upload these rates into the MIDAS platform. 3CE does not plan to upload transmission and distribution rates that are designed by the IOUs.
Plan for ensuring accuracy and maintenance of current time-dependent rates 3CE has worked with our back-office provider, Calpine, to ensure that rates uploads to MIDAS precedes customer billing on that rate. Calpine intends to streamline and update the rate transformation and upload process in the coming months in preparation for potential new requirements
16 such as supporting marginal rates as they are designed and deployed by various LSEs. Part of changes that Calpine anticipates depend heavily on the issues that arise with the MIDAS server. Calpine has reported that, historically, the MIDAS server has been fragile and slow. Calpine has had to adjust its uploading methods to accommodate a system that rejects rates when an upload packet is too large and at times has been fully inaccessible. If these issues persist, they would constitute a significant challenge for uploading marginal rates on a daily basis.
Internal infrastructure progress/upgrades for LMS-complaint submission to MIDAS 3CE’s back-office provider, Calpine, assisted with our successful and ongoing uploads to MIDAS by building a software application that transforms rate data into XML hourly streaming format and then uploads them to MIDAS through the provided API.
Uploading future marginal rates to the MIDAS server on a daily cadence will pose a significant challenge to Calpine. Calpine staff will need to devote regular meetings to tackling the issue of streamlining the current upload process, which to this point can take three days or longer, depending on the receptiveness of the MIDAS server. Calpine would need to build additional internal infrastructure to transform rates more quickly and find a way to upload them significantly faster than the server currently allows. Reporting for MIDAS uploads is currently manual and Calpine will need to develop automated reporting as a practical step for assuring 3CE that uploads are occurring timely and accurately.
Plan to provide RIN(s) on customer billing statements.
Implementation plan with timeline:
1623(c)(4) of the LMS requests that by March 31, 2024, Rate Identification Numbers (RINs) be incorporated into customer billing statements. Given that the IOUs act as billing agents, the design, placement and input for RINs on the bill by Large CCAs are restricted. Nevertheless, 3CE will collaborate with our IOU partners to furnish RINs and customer information, facilitating their inclusion in the billing statement.
Billing system updates
3CE’s back-office provider and IOUs have been in consistent communication to facilitate a plan for passing RINs created by Calpine to the IOUs for inclusion on customer invoices and to transform into QR codes. After several meetings, the IOUs have agreed to utilize the preferred Electronic Data Interchange 810 file (EDI 810) based on the merits of that EDI transaction set and in order to streamline the process across the different territories.
3CE foresees only one potential future issue, but has already reached a work-around until a more formal solution can be implemented by PG&E and Calpine. The rate ready billing method presents a unique challenge for passing RINs to PG&E because Calpine does not send 810s for those customers.
Calpine and PG&E have tentatively agreed that Calpine will provide PG&E with a list of rates and their corresponding RINs. With that, PG&E will be able to include the appropriate RINs and QR codes on the bills as an integrated part of the rate ready billing process.
Proposed text design and QR code design and proposed placement on billing statements As stated, the Large CCAs are limited by the IOUs in terms of design and placement of text and images on billing statements. However, 3CE is working with the IOUs to have consistent and understandable language regarding the RINs for customer understanding.
17 QR code linked webpage and design:
3CE anticipates that the QR code linked webpage on the customer bill will be to an IOU landing page that the Large CCAs have limited input. It is important that the Large CCAs be able to provide feedback to the IOUs, but we would likely augment the information with the webpages 3CE currently has. 3CE already supports the customer experience by having information on 3CE’s website that provides a description of 3CE’s rates and how rates are set and can provide a link to the MIDAS platform.
Additionally, 3CE’s website already provides information on 3CE’s customer rate options and eligible programs.
Plans and current participation in the development of Single Statewide RIN Access Tool Section 1623(c) requires the Large IOUs, Large POUs, and Large CCAs to develop a single statewide standard tool for authorized rate data access by third parties, along with a single set of terms and conditions for third parties using the tool, for submission to the CEC by October 1, 2024, for approval. 3CE has provided stakeholder input and participated in CEC workshops on the RIN Access Tool’s development held on January 17th, 2024. Stakeholders are awaiting a schedule for the development of the tool to be proposed by PG&E.
If the need for an extension is determined by stakeholders, the CEC Executive Director will be notified in accordance with section 1623(c)(2)(B) of the CEC’s LMS.
List of cost-effective LMS-compliant programs and rates 1623.1(b)(3) requests the Large CCAs to submit a list of load flexibility programs deemed cost effective to the Executive Director by October 1, 2024. At least one program must allow for automated responses to MIDAS signals for each customer class that the rate-approving body had determined the program would materially reduce peak load. The following section outline current and future opportunities of consideration for 3CE’s governing board, our rate-approving body.
Hourly-MIDAS signals-based load flexibility programs:
3CE’s board has already approved work to support demand management that responds to real-time pricing signals. The incorporation of hourly-MIDAS signals will be considered as the system is tested and proven it can be effectively integrated into 3CE and third-party platforms.
OhmConnect:
3CE entered into a marketing agreement with OhmConnect, a third-party demand response company, to help customers load shift. lower their electricity bill and earn rewards. OhmConnect is a free service that rewards utility customers in California and other states for saving energy. When customers can sign up toreceive alerts when energy is most expensive and non-renewable. If the customer saves electricity during peak times, OhmConnect will provide awards through gift cards or even cash via Paypal. OhmConnect is able to provide these rewards by bundling the energy savings of all of its users and selling it back to the California Independent System Operator’s (CAISO’s) energy markets. CAISO pays OhmConnect for the energy that wasn’t used.
Active Request for Proposals for Behind-the-Meter Battery Storage and Demand Response Program:
3CE currently is in process of soliciting and identifying an outside vendor to deploy behind-the-meter battery energy storage systems to increase local resiliency and provide new tools and capabilities that support 3CE’s goal of providing a portfolio of clean energy options to the communities and
18 customers we serve. 3CE is seeking industry partner(s) to design, implement, and manage an innovative, safe, and accessible battery energy storage system program that provides meaningful benefits to our customers. Additionally, 3CE is seeking a contractor(s) to design, implement, and manage a demand response program that leverages the batteries and potentially other grid-connected appliances to develop a suite of local distributed energy resources (DERs) that either 3CE or the program implementor can monitor and dispatch.
Potential Participation in CPUC Approved Programs
3CE is actively considering participation in CPUC Expanded Pilot opportunities across its service area, aligning with the California Energy Commission's Load Management Strategies (LMS):
Pacific Gas & Electric (PG&E) Expanded AgFIT Pilot:
The original Flexible Irrigation Pilot Program for Agriculture (AgFIT) aimed to help farms manage costs by optimizing energy load for irrigation. Decision (D.) 24-01-032 expanded the AgFIT program to all Agricultural end uses and allows all CCAs in PG&E's service area to participate until its conclusion on December 31, 2027.
Pilot Generation Rate:
For the generation components of the AgFIT pilot, energy costs (1) are based on CAISO wholesale market prices, and (2) generation and flexible capacity costs are recovered hourly using the scarcity pricing concept.4 The capacity cost recovery functions for all components will be calibrated to fully recover annual LSE generation costs and UDC delivery costs. Additional costs may be recovered through existing rate structures or a monthly subscription charge.
Target Customers:
The Expanded AgFIT Pilot is open to customers on AG-A1, AG-A2, AG-B, and AG-C rates for any end use.5
Enrollment & Load Impact Projections:
3CE aims to enroll 5MW of eligible load into the pilot program, adopting a measured approach for effective planning. Starting the pilot with a conservative goal is particularly critical for first-time pilot implementors, as it will allow newly participating CCAs to account for the rate of adoption and its potential impact on load forecasting while avoiding the risk of excessive energy procurement.
Customers Protections:
AgFIT utilizes a subscription model, enabling customers to plan their workload and associated costs. The subscription load shape is based on the customer's historic hourly usage, billed at the legacy rate. Deviations are billed at the dynamic volumetric rate. Shadow billing provides additional protection, tracking participants' load-shifting performance and compensation from both 3CE and PG&E. The customer would never pay more than their original tariff cost. 3 This
ensures minimal risk to customers, incentivizing participation by aligning operations with cost-effective power times. 4 California Public Utilities Commission. D.21-12-015. Accessed February 2024. https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M428/K821/428821475.PDF. 5 California Public Utilities Commission. D.24-01-032. Accessed February 2024. https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M524/K176/524176497.PDF.
19 The shadow billing method allows 3CE time to consider necessary billing upgrades and customer enhancements. As 3CE expresses interest, a commitment is made to equitable treatment for CCA customers. If PG&E mismanages the pilot, 3CE may proceed with its own AgFIT-inspired pilot in the future.
Equipment Requirements:
While automation equipment can assist in load-shifting, it is not necessary for the AgFIT pilot.6 Third-party Automation Providers:
As determined by D. 24-01-032, PG&E will manage contracts with third-party vendors. In the Expanded AgFIT Pilot, PG&E would collaborate with third-party automation service providers.
PG&E’s Expanded Pilot 2:
Using the same model as the original AgFIT program, D.24-01-032 also directed PG&E to offer a new secondary pilot that enrolls both residential and commercial rates (B-6, B-10, B-19, B-20, E-ELEC, and EV2-A). 3CE will continue to monitor this opportunity and the potential benefits to our customers.
Southern California Edison (SCE) Dynamic Rate Pilot:
SCE is conducting the CalFUSE Dynamic Rate Pilot, expanded to CCAs by D. 24-01-032. The generation component includes a capacity price function with day-ahead CAISO energy as a passthrough. If 3CE participates, valuable insights for an marginal cost rate design, incorporating day-ahead CAISO Default Load Aggregation Point (DLAP) pricing to meet the CEC’s LMS would be gained. 3CE is actively evaluating this new potential partnership opportunity.
Additional Information Regarding Marginal Cost Rates & Programs In formulating any rate or program, 3CE considers the distinctive requirements of our service area. Our commitment revolves around investing in the communities we serve, ensuring competitively priced rates, and offering energy program rebates and incentives that facilitate the transition of 3CE customers' homes, workplaces, and transportation from fossil fuel power to clean energy solutions.
Two notable features of 3CE set it apart: first, it stands as the largest CCA geographically, spanning over five counties across the central coast. Second, it caters to a substantial number of Agricultural customers, constituting approximately 22% of our total load. The communities and business operations within 3CE’s service area are diverse, with varying factors like the types of crops grown by farmers influencing when and how they can modify their energy usage. This diversity extends to encompass small and large businesses, as well as residential customers across our service area. Below, Graph 1 provides insight by showing the breakdown of our load by various customer types. Given this vast geography and diverse customer base, it is crucial to consider the distinctive needs and usage behaviors of all customers when introducing new programs and rates. 6 Polaris Energy Services. “Polaris +Valley Clean Energy | 2022 Incentive Program.” Youtube video. August 18, 2022. https://www.youtube.com/watch?v=JnJJCIVSs_c
20 Graph 1: 2023 Electric Load Percentage by Customer Type Public Information Program on Marginal Cost Rates/Programs Section 1623.1(b)(5) of the LMS asks the Large CCAs to conduct a public information program to inform and educate affected customers why marginal cost-based rates or load flexibility programs and automation are needed, how they will be used, and how these rates and programs can save customers money.
3CE has a successful history of educating its customers spanning two IOU service areas on various energy related initiatives. These experiences include marketing the Time of Use Transition, our Cost-of-Service Rate launch, highlighting customer programs like CARE, FERA, AMP, CAPP and PIPP, and promoting our portfolio of energy programs and initiatives. 3CE also maintains consistent communication across its five-county region through monthly newsletters and social media posts.
In order to reduce costs and boost enrollment, a Public Information Program would be run in conjunction with the launch of a board approved rate or program to eligible customer classes. 3CE would design a campaign that may include direct mail, website, social media, newsletter articles, monthly content shares, and public presentations. 3CE would also consider working with community partners to ensure that all customer segments are reached.
At a minimum, 3CE would to have expand existing contracts with vendors to conduct graphic design, media buying, and video production as necessary. Staff time would also be dedicated and is anticipated at 25% of a full time Marketing and Communications staff member and 30% of a full time Accounts Management staff person.
Conclusion
3CE expresses gratitude to its Policy Board for considering this plan and for their leadership in adopting programs and rates that benefit the communities we serve. The plan underscores 3CE's dedication to supporting the Central Coast region through grid reliability and customer-focused programs. It is important to note that the adoption of this plan and its considerations are subject to potential changes by our governing boards. New information on marginal rates and programs, as well as evolving customer needs, may influence these decisions.
21 Looking ahead, this plan remains flexible, open to adjustments as new information and opportunities emerge. 3CE staff will continuously assess opportunities to uphold reliability and align with the state's goals. The organization will explore rate and program designs that align with its values and support customers. As long as 3CE's goals, guided by our governing boards, align with those outlined in the CEC’s LMS, the organization will voluntarily strive to meet the indicated standards.
22 Attachment A: MIDAS Rate Imports
Rate Name RIN - Calpine RIN - MIDAS
A-1-B Choice Flat USCA-XXMB-0001-PGE USCA-XXMB-0001-PGE A-1-B Choice GR1 USCA-XXMB-0002-PGE USCA-XXMB-0002-PGE
A-1-B Prime Flat USCA-XXMB-0003-PGE USCA-XXMB-0003-PGE
A-1-B Prime GR1 USCA-XXMB-0004-PGE USCA-XXMB-0004-PGE
A-10-B-P Choice Flat USCA-XXMB-0005-PGE USCA-XXMB-0005-PGE A-10-B-P Choice GR1 USCA-XXMB-0006-PGE USCA-XXMB-0006-PGE A-10-B-P Prime Flat USCA-XXMB-0007-PGE USCA-XXMB-0007-PGE A-10-B-P Prime GR1 USCA-XXMB-0008-PGE USCA-XXMB-0008-PGE A-10-B-S Choice Flat USCA-XXMB-0009-PGE USCA-XXMB-0009-PGE A-10-B-S Choice GR1 USCA-XXMB-0010-PGE USCA-XXMB-0010-PGE A-10-B-S Prime Flat USCA-XXMB-0011-PGE USCA-XXMB-0011-PGE A-10-B-S Prime GR1 USCA-XXMB-0012-PGE USCA-XXMB-0012-PGE A-10-B-T Choice Flat USCA-XXMB-0013-PGE USCA-XXMB-0013-PGE A-10-B-T Choice GR1 USCA-XXMB-0014-PGE USCA-XXMB-0014-PGE A-10-B-T Prime Flat USCA-XXMB-0015-PGE USCA-XXMB-0015-PGE A-10-B-T Prime GR1 USCA-XXMB-0016-PGE USCA-XXMB-0016-PGE A-6 Choice Flat USCA-XXMB-0017-PGE USCA-XXMB-0017-PGE
A-6 Choice GR1 USCA-XXMB-0018-PGE USCA-XXMB-0018-PGE
A-6 Prime Flat USCA-XXMB-0019-PGE USCA-XXMB-0019-PGE
A-6 Prime GR1 USCA-XXMB-0020-PGE USCA-XXMB-0020-PGE
AG-4-A Choice Flat USCA-XXMB-0021-PGE USCA-XXMB-0021-PGE AG-4-A Choice GR1 USCA-XXMB-0022-PGE USCA-XXMB-0022-PGE AG-4-A Prime Flat USCA-XXMB-0023-PGE USCA-XXMB-0023-PGE AG-4-A Prime GR1 USCA-XXMB-0024-PGE USCA-XXMB-0024-PGE
AG-4-B-P Choice Flat USCA-XXMB-0025-PGE USCA-XXMB-0025-PGE AG-4-B-P Choice GR1 USCA-XXMB-0026-PGE USCA-XXMB-0026-PGE AG-4-B-P Prime Flat USCA-XXMB-0027-PGE USCA-XXMB-0027-PGE AG-4-B-P Prime GR1 USCA-XXMB-0028-PGE USCA-XXMB-0028-PGE AG-4-B-S Choice Flat USCA-XXMB-0029-PGE USCA-XXMB-0029-PGE AG-4-B-S Choice GR1 USCA-XXMB-0030-PGE USCA-XXMB-0030-PGE AG-4-B-S Prime Flat USCA-XXMB-0031-PGE USCA-XXMB-0031-PGE AG-4-B-S Prime GR1 USCA-XXMB-0032-PGE USCA-XXMB-0032-PGE AG-4-B-T Choice Flat USCA-XXMB-0033-PGE USCA-XXMB-0033-PGE AG-4-B-T Choice GR1 USCA-XXMB-0034-PGE USCA-XXMB-0034-PGE AG-4-B-T Prime Flat USCA-XXMB-0035-PGE USCA-XXMB-0035-PGE AG-4-B-T Prime GR1 USCA-XXMB-0036-PGE USCA-XXMB-0036-PGE AG-4-C-P Choice Flat USCA-XXMB-0037-PGE USCA-XXMB-0037-PGE
23 AG-4-C-P Choice GR1 USCA-XXMB-0038-PGE USCA-XXMB-0038-PGE AG-4-C-P Prime Flat USCA-XXMB-0039-PGE USCA-XXMB-0039-PGE AG-4-C-P Prime GR1 USCA-XXMB-0040-PGE USCA-XXMB-0040-PGE AG-4-C-S Choice Flat USCA-XXMB-0041-PGE USCA-XXMB-0041-PGE AG-4-C-S Choice GR1 USCA-XXMB-0042-PGE USCA-XXMB-0042-PGE AG-4-C-S Prime Flat USCA-XXMB-0043-PGE USCA-XXMB-0043-PGE AG-4-C-S Prime GR1 USCA-XXMB-0044-PGE USCA-XXMB-0044-PGE AG-4-C-T Choice Flat USCA-XXMB-0045-PGE USCA-XXMB-0045-PGE AG-4-C-T Choice GR1 USCA-XXMB-0046-PGE USCA-XXMB-0046-PGE AG-4-C-T Prime Flat USCA-XXMB-0047-PGE USCA-XXMB-0047-PGE AG-4-C-T Prime GR1 USCA-XXMB-0048-PGE USCA-XXMB-0048-PGE AG-5-A Choice Flat USCA-XXMB-0049-PGE USCA-XXMB-0049-PGE AG-5-A Choice GR1 USCA-XXMB-0050-PGE USCA-XXMB-0050-PGE AG-5-A Prime Flat USCA-XXMB-0051-PGE USCA-XXMB-0051-PGE AG-5-A Prime GR1 USCA-XXMB-0052-PGE USCA-XXMB-0052-PGE
AG-5-B-P Choice Flat USCA-XXMB-0053-PGE USCA-XXMB-0053-PGE AG-5-B-P Choice GR1 USCA-XXMB-0054-PGE USCA-XXMB-0054-PGE AG-5-B-P Prime Flat USCA-XXMB-0055-PGE USCA-XXMB-0055-PGE AG-5-B-P Prime GR1 USCA-XXMB-0056-PGE USCA-XXMB-0056-PGE AG-5-B-S Choice Flat USCA-XXMB-0057-PGE USCA-XXMB-0057-PGE AG-5-B-S Choice GR1 USCA-XXMB-0058-PGE USCA-XXMB-0058-PGE AG-5-B-S Prime Flat USCA-XXMB-0059-PGE USCA-XXMB-0059-PGE AG-5-B-S Prime GR1 USCA-XXMB-0060-PGE USCA-XXMB-0060-PGE AG-5-B-T Choice Flat USCA-XXMB-0061-PGE USCA-XXMB-0061-PGE AG-5-B-T Choice GR1 USCA-XXMB-0062-PGE USCA-XXMB-0062-PGE AG-5-B-T Prime Flat USCA-XXMB-0063-PGE USCA-XXMB-0063-PGE AG-5-B-T Prime GR1 USCA-XXMB-0064-PGE USCA-XXMB-0064-PGE AG-5-C-P Choice Flat USCA-XXMB-0065-PGE USCA-XXMB-0065-PGE AG-5-C-P Choice GR1 USCA-XXMB-0066-PGE USCA-XXMB-0066-PGE AG-5-C-P Prime Flat USCA-XXMB-0067-PGE USCA-XXMB-0067-PGE AG-5-C-P Prime GR1 USCA-XXMB-0068-PGE USCA-XXMB-0068-PGE AG-5-C-S Choice Flat USCA-XXMB-0069-PGE USCA-XXMB-0069-PGE AG-5-C-S Choice GR1 USCA-XXMB-0070-PGE USCA-XXMB-0070-PGE AG-5-C-S Prime Flat USCA-XXMB-0071-PGE USCA-XXMB-0071-PGE AG-5-C-S Prime GR1 USCA-XXMB-0072-PGE USCA-XXMB-0072-PGE AG-5-C-T Choice Flat USCA-XXMB-0073-PGE USCA-XXMB-0073-PGE AG-5-C-T Choice GR1 USCA-XXMB-0074-PGE USCA-XXMB-0074-PGE AG-5-C-T Prime Flat USCA-XXMB-0075-PGE USCA-XXMB-0075-PGE AG-5-C-T Prime GR1 USCA-XXMB-0076-PGE USCA-XXMB-0076-PGE AG-A1 Choice Flat USCA-XXMB-0077-PGE USCA-XXMB-0077-PGE AG-A1 Choice GR1 USCA-XXMB-0078-PGE USCA-XXMB-0078-PGE
24 AG-A1 Prime Flat USCA-XXMB-0079-PGE USCA-XXMB-0079-PGE AG-A1 Prime GR1 USCA-XXMB-0080-PGE USCA-XXMB-0080-PGE
AG-A2 Choice Flat USCA-XXMB-0081-PGE USCA-XXMB-0081-PGE AG-A2 Choice GR1 USCA-XXMB-0082-PGE USCA-XXMB-0082-PGE
AG-A2 Prime Flat USCA-XXMB-0083-PGE USCA-XXMB-0083-PGE
AG-A2 Prime GR1 USCA-XXMB-0084-PGE USCA-XXMB-0084-PGE
AG-B Choice Flat USCA-XXMB-0085-PGE USCA-XXMB-0085-PGE
AG-B Choice GR1 USCA-XXMB-0086-PGE USCA-XXMB-0086-PGE
AG-B Prime Flat USCA-XXMB-0087-PGE USCA-XXMB-0087-PGE
AG-B Prime GR1 USCA-XXMB-0088-PGE USCA-XXMB-0088-PGE
AG-C Choice Flat USCA-XXMB-0089-PGE USCA-XXMB-0089-PGE
AG-C Choice GR1 USCA-XXMB-0090-PGE USCA-XXMB-0090-PGE
AG-C Prime Flat USCA-XXMB-0091-PGE USCA-XXMB-0091-PGE
AG-C Prime GR1 USCA-XXMB-0092-PGE USCA-XXMB-0092-PGE
AG-F-A1 Choice Flat USCA-XXMB-0093-PGE USCA-XXMB-0093-PGE AG-F-A1 Choice GR1 USCA-XXMB-0094-PGE USCA-XXMB-0094-PGE AG-F-A1 Prime Flat USCA-XXMB-0095-PGE USCA-XXMB-0095-PGE AG-F-A1 Prime GR1 USCA-XXMB-0096-PGE USCA-XXMB-0096-PGE AG-F-A2 Choice Flat USCA-XXMB-0097-PGE USCA-XXMB-0097-PGE AG-F-A2 Choice GR1 USCA-XXMB-0098-PGE USCA-XXMB-0098-PGE AG-F-A2 Prime Flat USCA-XXMB-0099-PGE USCA-XXMB-0099-PGE AG-F-A2 Prime GR1 USCA-XXMB-0100-PGE USCA-XXMB-0100-PGE AG-F-A3 Choice Flat USCA-XXMB-0101-PGE USCA-XXMB-0101-PGE AG-F-A3 Choice GR1 USCA-XXMB-0102-PGE USCA-XXMB-0102-PGE AG-F-A3 Prime Flat USCA-XXMB-0103-PGE USCA-XXMB-0103-PGE AG-F-A3 Prime GR1 USCA-XXMB-0104-PGE USCA-XXMB-0104-PGE AG-F-B1 Choice Flat USCA-XXMB-0105-PGE USCA-XXMB-0105-PGE AG-F-B1 Choice GR1 USCA-XXMB-0106-PGE USCA-XXMB-0106-PGE AG-F-B1 Prime Flat USCA-XXMB-0107-PGE USCA-XXMB-0107-PGE AG-F-B1 Prime GR1 USCA-XXMB-0108-PGE USCA-XXMB-0108-PGE AG-F-B2 Choice Flat USCA-XXMB-0109-PGE USCA-XXMB-0109-PGE AG-F-B2 Choice GR1 USCA-XXMB-0110-PGE USCA-XXMB-0110-PGE AG-F-B2 Prime Flat USCA-XXMB-0111-PGE USCA-XXMB-0111-PGE AG-F-B2 Prime GR1 USCA-XXMB-0112-PGE USCA-XXMB-0112-PGE AG-F-B3 Choice Flat USCA-XXMB-0113-PGE USCA-XXMB-0113-PGE AG-F-B3 Choice GR1 USCA-XXMB-0114-PGE USCA-XXMB-0114-PGE AG-F-B3 Prime Flat USCA-XXMB-0115-PGE USCA-XXMB-0115-PGE AG-F-B3 Prime GR1 USCA-XXMB-0116-PGE USCA-XXMB-0116-PGE AG-F-C1 Choice Flat USCA-XXMB-0117-PGE USCA-XXMB-0117-PGE AG-F-C1 Choice GR1 USCA-XXMB-0118-PGE USCA-XXMB-0118-PGE AG-F-C1 Prime Flat USCA-XXMB-0119-PGE USCA-XXMB-0119-PGE
25 AG-F-C1 Prime GR1 USCA-XXMB-0120-PGE USCA-XXMB-0120-PGE AG-F-C2 Choice Flat USCA-XXMB-0121-PGE USCA-XXMB-0121-PGE AG-F-C2 Choice GR1 USCA-XXMB-0122-PGE USCA-XXMB-0122-PGE AG-F-C2 Prime Flat USCA-XXMB-0123-PGE USCA-XXMB-0123-PGE AG-F-C2 Prime GR1 USCA-XXMB-0124-PGE USCA-XXMB-0124-PGE AG-F-C3 Choice Flat USCA-XXMB-0125-PGE USCA-XXMB-0125-PGE AG-F-C3 Choice GR1 USCA-XXMB-0126-PGE USCA-XXMB-0126-PGE AG-F-C3 Prime Flat USCA-XXMB-0127-PGE USCA-XXMB-0127-PGE AG-F-C3 Prime GR1 USCA-XXMB-0128-PGE USCA-XXMB-0128-PGE AG-R-A Choice Flat USCA-XXMB-0129-PGE USCA-XXMB-0129-PGE AG-R-A Choice GR1 USCA-XXMB-0130-PGE USCA-XXMB-0130-PGE AG-R-A Prime Flat USCA-XXMB-0131-PGE USCA-XXMB-0131-PGE AG-R-A Prime GR1 USCA-XXMB-0132-PGE USCA-XXMB-0132-PGE
AG-R-B-P Choice Flat USCA-XXMB-0133-PGE USCA-XXMB-0133-PGE AG-R-B-P Choice GR1 USCA-XXMB-0134-PGE USCA-XXMB-0134-PGE AG-R-B-P Prime Flat USCA-XXMB-0135-PGE USCA-XXMB-0135-PGE AG-R-B-P Prime GR1 USCA-XXMB-0136-PGE USCA-XXMB-0136-PGE AG-R-B-S Choice Flat USCA-XXMB-0137-PGE USCA-XXMB-0137-PGE AG-R-B-S Choice GR1 USCA-XXMB-0138-PGE USCA-XXMB-0138-PGE AG-R-B-S Prime Flat USCA-XXMB-0139-PGE USCA-XXMB-0139-PGE AG-R-B-S Prime GR1 USCA-XXMB-0140-PGE USCA-XXMB-0140-PGE AG-R-B-T Choice Flat USCA-XXMB-0141-PGE USCA-XXMB-0141-PGE AG-R-B-T Choice GR1 USCA-XXMB-0142-PGE USCA-XXMB-0142-PGE AG-R-B-T Prime Flat USCA-XXMB-0143-PGE USCA-XXMB-0143-PGE AG-R-B-T Prime GR1 USCA-XXMB-0144-PGE USCA-XXMB-0144-PGE AG-V-A Choice Flat USCA-XXMB-0145-PGE USCA-XXMB-0145-PGE AG-V-A Choice GR1 USCA-XXMB-0146-PGE USCA-XXMB-0146-PGE AG-V-A Prime Flat USCA-XXMB-0147-PGE USCA-XXMB-0147-PGE AG-V-A Prime GR1 USCA-XXMB-0148-PGE USCA-XXMB-0148-PGE
AG-V-B-P Choice Flat USCA-XXMB-0149-PGE USCA-XXMB-0149-PGE AG-V-B-P Choice GR1 USCA-XXMB-0150-PGE USCA-XXMB-0150-PGE AG-V-B-P Prime Flat USCA-XXMB-0151-PGE USCA-XXMB-0151-PGE AG-V-B-P Prime GR1 USCA-XXMB-0152-PGE USCA-XXMB-0152-PGE AG-V-B-S Choice Flat USCA-XXMB-0153-PGE USCA-XXMB-0153-PGE AG-V-B-S Choice GR1 USCA-XXMB-0154-PGE USCA-XXMB-0154-PGE AG-V-B-S Prime Flat USCA-XXMB-0155-PGE USCA-XXMB-0155-PGE AG-V-B-S Prime GR1 USCA-XXMB-0156-PGE USCA-XXMB-0156-PGE AG-V-B-T Choice Flat USCA-XXMB-0157-PGE USCA-XXMB-0157-PGE AG-V-B-T Choice GR1 USCA-XXMB-0158-PGE USCA-XXMB-0158-PGE AG-V-B-T Prime Flat USCA-XXMB-0159-PGE USCA-XXMB-0159-PGE AG-V-B-T Prime GR1 USCA-XXMB-0160-PGE USCA-XXMB-0160-PGE
26 B-1 Choice Flat USCA-XXMB-0161-PGE USCA-XXMB-0161-PGE B-1 Choice GR1 USCA-XXMB-0162-PGE USCA-XXMB-0162-PGE
B-1 Prime Flat USCA-XXMB-0163-PGE USCA-XXMB-0163-PGE
B-1 Prime GR1 USCA-XXMB-0164-PGE USCA-XXMB-0164-PGE
B-1-ST Choice Flat USCA-XXMB-0165-PGE USCA-XXMB-0165-PGE B-1-ST Choice GR1 USCA-XXMB-0166-PGE USCA-XXMB-0166-PGE B-1-ST Prime Flat USCA-XXMB-0167-PGE USCA-XXMB-0167-PGE B-1-ST Prime GR1 USCA-XXMB-0168-PGE USCA-XXMB-0168-PGE
B-10-P Choice Flat USCA-XXMB-0169-PGE USCA-XXMB-0169-PGE B-10-P Choice GR1 USCA-XXMB-0170-PGE USCA-XXMB-0170-PGE B-10-P Prime Flat USCA-XXMB-0171-PGE USCA-XXMB-0171-PGE B-10-P Prime GR1 USCA-XXMB-0172-PGE USCA-XXMB-0172-PGE
B-10-S Choice Flat USCA-XXMB-0173-PGE USCA-XXMB-0173-PGE B-10-S Choice GR1 USCA-XXMB-0174-PGE USCA-XXMB-0174-PGE B-10-S Prime Flat USCA-XXMB-0175-PGE USCA-XXMB-0175-PGE B-10-S Prime GR1 USCA-XXMB-0176-PGE USCA-XXMB-0176-PGE
B-10-T Choice Flat USCA-XXMB-0177-PGE USCA-XXMB-0177-PGE B-10-T Choice GR1 USCA-XXMB-0178-PGE USCA-XXMB-0178-PGE B-10-T Prime Flat USCA-XXMB-0179-PGE USCA-XXMB-0179-PGE B-10-T Prime GR1 USCA-XXMB-0180-PGE USCA-XXMB-0180-PGE
B-19-P Choice Flat USCA-XXMB-0181-PGE USCA-XXMB-0181-PGE B-19-P Choice GR1 USCA-XXMB-0182-PGE USCA-XXMB-0182-PGE B-19-P Prime Flat USCA-XXMB-0183-PGE USCA-XXMB-0183-PGE B-19-P Prime GR1 USCA-XXMB-0184-PGE USCA-XXMB-0184-PGE
B-19-R-P Choice Flat USCA-XXMB-0185-PGE USCA-XXMB-0185-PGE B-19-R-P Choice GR1 USCA-XXMB-0186-PGE USCA-XXMB-0186-PGE B-19-R-P Prime Flat USCA-XXMB-0187-PGE USCA-XXMB-0187-PGE B-19-R-P Prime GR1 USCA-XXMB-0188-PGE USCA-XXMB-0188-PGE B-19-R-S Choice Flat USCA-XXMB-0189-PGE USCA-XXMB-0189-PGE B-19-R-S Choice GR1 USCA-XXMB-0190-PGE USCA-XXMB-0190-PGE B-19-R-S Prime Flat USCA-XXMB-0191-PGE USCA-XXMB-0191-PGE B-19-R-S Prime GR1 USCA-XXMB-0192-PGE USCA-XXMB-0192-PGE B-19-R-T Choice Flat USCA-XXMB-0193-PGE USCA-XXMB-0193-PGE B-19-R-T Choice GR1 USCA-XXMB-0194-PGE USCA-XXMB-0194-PGE B-19-R-T Prime Flat USCA-XXMB-0195-PGE USCA-XXMB-0195-PGE B-19-R-T Prime GR1 USCA-XXMB-0196-PGE USCA-XXMB-0196-PGE B-19-S Choice Flat USCA-XXMB-0197-PGE USCA-XXMB-0197-PGE B-19-S Choice GR1 USCA-XXMB-0198-PGE USCA-XXMB-0198-PGE B-19-S Prime Flat USCA-XXMB-0199-PGE USCA-XXMB-0199-PGE B-19-S Prime GR1 USCA-XXMB-0200-PGE USCA-XXMB-0200-PGE
B-19-S-P Choice Flat USCA-XXMB-0201-PGE USCA-XXMB-0201-PGE
27 B-19-S-P Choice GR1 USCA-XXMB-0202-PGE USCA-XXMB-0202-PGE B-19-S-P Prime Flat USCA-XXMB-0203-PGE USCA-XXMB-0203-PGE B-19-S-P Prime GR1 USCA-XXMB-0204-PGE USCA-XXMB-0204-PGE B-19-S-S Choice Flat USCA-XXMB-0205-PGE USCA-XXMB-0205-PGE B-19-S-S Choice GR1 USCA-XXMB-0206-PGE USCA-XXMB-0206-PGE B-19-S-S Prime Flat USCA-XXMB-0207-PGE USCA-XXMB-0207-PGE B-19-S-S Prime GR1 USCA-XXMB-0208-PGE USCA-XXMB-0208-PGE B-19-S-T Choice Flat USCA-XXMB-0209-PGE USCA-XXMB-0209-PGE B-19-S-T Choice GR1 USCA-XXMB-0210-PGE USCA-XXMB-0210-PGE B-19-S-T Prime Flat USCA-XXMB-0211-PGE USCA-XXMB-0211-PGE B-19-S-T Prime GR1 USCA-XXMB-0212-PGE USCA-XXMB-0212-PGE B-19-T Choice Flat USCA-XXMB-0213-PGE USCA-XXMB-0213-PGE B-19-T Choice GR1 USCA-XXMB-0214-PGE USCA-XXMB-0214-PGE B-19-T Prime Flat USCA-XXMB-0215-PGE USCA-XXMB-0215-PGE B-19-T Prime GR1 USCA-XXMB-0216-PGE USCA-XXMB-0216-PGE
B-20-P Choice Flat USCA-XXMB-0217-PGE USCA-XXMB-0217-PGE B-20-P Choice GR1 USCA-XXMB-0218-PGE USCA-XXMB-0218-PGE B-20-P Prime Flat USCA-XXMB-0219-PGE USCA-XXMB-0219-PGE B-20-P Prime GR1 USCA-XXMB-0220-PGE USCA-XXMB-0220-PGE
B-20-R-P Choice Flat USCA-XXMB-0221-PGE USCA-XXMB-0221-PGE B-20-R-P Choice GR1 USCA-XXMB-0222-PGE USCA-XXMB-0222-PGE B-20-R-P Prime Flat USCA-XXMB-0223-PGE USCA-XXMB-0223-PGE B-20-R-P Prime GR1 USCA-XXMB-0224-PGE USCA-XXMB-0224-PGE B-20-R-S Choice Flat USCA-XXMB-0225-PGE USCA-XXMB-0225-PGE B-20-R-S Choice GR1 USCA-XXMB-0226-PGE USCA-XXMB-0226-PGE B-20-R-S Prime Flat USCA-XXMB-0227-PGE USCA-XXMB-0227-PGE B-20-R-S Prime GR1 USCA-XXMB-0228-PGE USCA-XXMB-0228-PGE B-20-R-T Choice Flat USCA-XXMB-0229-PGE USCA-XXMB-0229-PGE B-20-R-T Choice GR1 USCA-XXMB-0230-PGE USCA-XXMB-0230-PGE B-20-R-T Prime Flat USCA-XXMB-0231-PGE USCA-XXMB-0231-PGE B-20-R-T Prime GR1 USCA-XXMB-0232-PGE USCA-XXMB-0232-PGE B-20-S Choice Flat USCA-XXMB-0233-PGE USCA-XXMB-0233-PGE B-20-S Choice GR1 USCA-XXMB-0234-PGE USCA-XXMB-0234-PGE B-20-S Prime Flat USCA-XXMB-0235-PGE USCA-XXMB-0235-PGE B-20-S Prime GR1 USCA-XXMB-0236-PGE USCA-XXMB-0236-PGE
B-20-S-P Choice Flat USCA-XXMB-0237-PGE USCA-XXMB-0237-PGE B-20-S-P Choice GR1 USCA-XXMB-0238-PGE USCA-XXMB-0238-PGE B-20-S-P Prime Flat USCA-XXMB-0239-PGE USCA-XXMB-0239-PGE B-20-S-P Prime GR1 USCA-XXMB-0240-PGE USCA-XXMB-0240-PGE B-20-S-S Choice Flat USCA-XXMB-0241-PGE USCA-XXMB-0241-PGE B-20-S-S Choice GR1 USCA-XXMB-0242-PGE USCA-XXMB-0242-PGE
28 B-20-S-S Prime Flat USCA-XXMB-0243-PGE USCA-XXMB-0243-PGE B-20-S-S Prime GR1 USCA-XXMB-0244-PGE USCA-XXMB-0244-PGE B-20-S-T Choice Flat USCA-XXMB-0245-PGE USCA-XXMB-0245-PGE B-20-S-T Choice GR1 USCA-XXMB-0246-PGE USCA-XXMB-0246-PGE B-20-S-T Prime Flat USCA-XXMB-0247-PGE USCA-XXMB-0247-PGE B-20-S-T Prime GR1 USCA-XXMB-0248-PGE USCA-XXMB-0248-PGE B-20-T Choice Flat USCA-XXMB-0249-PGE USCA-XXMB-0249-PGE B-20-T Choice GR1 USCA-XXMB-0250-PGE USCA-XXMB-0250-PGE B-20-T Prime Flat USCA-XXMB-0251-PGE USCA-XXMB-0251-PGE B-20-T Prime GR1 USCA-XXMB-0252-PGE USCA-XXMB-0252-PGE
B-6 Choice Flat USCA-XXMB-0253-PGE USCA-XXMB-0253-PGE
B-6 Choice GR1 USCA-XXMB-0254-PGE USCA-XXMB-0254-PGE
B-6 Prime Flat USCA-XXMB-0255-PGE USCA-XXMB-0255-PGE
B-6 Prime GR1 USCA-XXMB-0256-PGE USCA-XXMB-0256-PGE
B-EV-1 Choice Flat USCA-XXMB-0257-PGE USCA-XXMB-0257-PGE B-EV-1 Choice GR1 USCA-XXMB-0258-PGE USCA-XXMB-0258-PGE B-EV-1 Prime Flat USCA-XXMB-0259-PGE USCA-XXMB-0259-PGE B-EV-1 Prime GR1 USCA-XXMB-0260-PGE USCA-XXMB-0260-PGE
B-EV-2-P Choice Flat USCA-XXMB-0261-PGE USCA-XXMB-0261-PGE B-EV-2-P Choice GR1 USCA-XXMB-0262-PGE USCA-XXMB-0262-PGE B-EV-2-P Prime Flat USCA-XXMB-0263-PGE USCA-XXMB-0263-PGE B-EV-2-P Prime GR1 USCA-XXMB-0264-PGE USCA-XXMB-0264-PGE B-EV-2-S Choice Flat USCA-XXMB-0265-PGE USCA-XXMB-0265-PGE B-EV-2-S Choice GR1 USCA-XXMB-0266-PGE USCA-XXMB-0266-PGE B-EV-2-S Prime Flat USCA-XXMB-0267-PGE USCA-XXMB-0267-PGE B-EV-2-S Prime GR1 USCA-XXMB-0268-PGE USCA-XXMB-0268-PGE E-19-P Choice Flat USCA-XXMB-0269-PGE USCA-XXMB-0269-PGE E-19-P Choice GR1 USCA-XXMB-0270-PGE USCA-XXMB-0270-PGE E-19-P Prime Flat USCA-XXMB-0271-PGE USCA-XXMB-0271-PGE E-19-P Prime GR1 USCA-XXMB-0272-PGE USCA-XXMB-0272-PGE
E-19-R-P Choice Flat USCA-XXMB-0273-PGE USCA-XXMB-0273-PGE E-19-R-P Choice GR1 USCA-XXMB-0274-PGE USCA-XXMB-0274-PGE E-19-R-P Prime Flat USCA-XXMB-0275-PGE USCA-XXMB-0275-PGE E-19-R-P Prime GR1 USCA-XXMB-0276-PGE USCA-XXMB-0276-PGE E-19-R-S Choice Flat USCA-XXMB-0277-PGE USCA-XXMB-0277-PGE E-19-R-S Choice GR1 USCA-XXMB-0278-PGE USCA-XXMB-0278-PGE E-19-R-S Prime Flat USCA-XXMB-0279-PGE USCA-XXMB-0279-PGE E-19-R-S Prime GR1 USCA-XXMB-0280-PGE USCA-XXMB-0280-PGE E-19-R-T Choice Flat USCA-XXMB-0281-PGE USCA-XXMB-0281-PGE E-19-R-T Choice GR1 USCA-XXMB-0282-PGE USCA-XXMB-0282-PGE E-19-R-T Prime Flat USCA-XXMB-0283-PGE USCA-XXMB-0283-PGE
29 E-19-R-T Prime GR1 USCA-XXMB-0284-PGE USCA-XXMB-0284-PGE E-19-S Choice Flat USCA-XXMB-0285-PGE USCA-XXMB-0285-PGE E-19-S Choice GR1 USCA-XXMB-0286-PGE USCA-XXMB-0286-PGE E-19-S Prime Flat USCA-XXMB-0287-PGE USCA-XXMB-0287-PGE E-19-S Prime GR1 USCA-XXMB-0288-PGE USCA-XXMB-0288-PGE
E-19-T Choice Flat USCA-XXMB-0289-PGE USCA-XXMB-0289-PGE E-19-T Choice GR1 USCA-XXMB-0290-PGE USCA-XXMB-0290-PGE E-19-T Prime Flat USCA-XXMB-0291-PGE USCA-XXMB-0291-PGE E-19-T Prime GR1 USCA-XXMB-0292-PGE USCA-XXMB-0292-PGE
E-20-P Choice Flat USCA-XXMB-0293-PGE USCA-XXMB-0293-PGE E-20-P Choice GR1 USCA-XXMB-0294-PGE USCA-XXMB-0294-PGE E-20-P Prime Flat USCA-XXMB-0295-PGE USCA-XXMB-0295-PGE E-20-P Prime GR1 USCA-XXMB-0296-PGE USCA-XXMB-0296-PGE
E-20-R-P Choice Flat USCA-XXMB-0297-PGE USCA-XXMB-0297-PGE E-20-R-P Choice GR1 USCA-XXMB-0298-PGE USCA-XXMB-0298-PGE E-20-R-P Prime Flat USCA-XXMB-0299-PGE USCA-XXMB-0299-PGE E-20-R-P Prime GR1 USCA-XXMB-0300-PGE USCA-XXMB-0300-PGE E-20-R-S Choice Flat USCA-XXMB-0301-PGE USCA-XXMB-0301-PGE E-20-R-S Choice GR1 USCA-XXMB-0302-PGE USCA-XXMB-0302-PGE E-20-R-S Prime Flat USCA-XXMB-0303-PGE USCA-XXMB-0303-PGE E-20-R-S Prime GR1 USCA-XXMB-0304-PGE USCA-XXMB-0304-PGE E-20-R-T Choice Flat USCA-XXMB-0305-PGE USCA-XXMB-0305-PGE E-20-R-T Choice GR1 USCA-XXMB-0306-PGE USCA-XXMB-0306-PGE E-20-R-T Prime Flat USCA-XXMB-0307-PGE USCA-XXMB-0307-PGE E-20-R-T Prime GR1 USCA-XXMB-0308-PGE USCA-XXMB-0308-PGE E-20-S Choice Flat USCA-XXMB-0309-PGE USCA-XXMB-0309-PGE E-20-S Choice GR1 USCA-XXMB-0310-PGE USCA-XXMB-0310-PGE E-20-S Prime Flat USCA-XXMB-0311-PGE USCA-XXMB-0311-PGE E-20-S Prime GR1 USCA-XXMB-0312-PGE USCA-XXMB-0312-PGE
E-20-T Choice Flat USCA-XXMB-0313-PGE USCA-XXMB-0313-PGE E-20-T Choice GR1 USCA-XXMB-0314-PGE USCA-XXMB-0314-PGE E-20-T Prime Flat USCA-XXMB-0315-PGE USCA-XXMB-0315-PGE E-20-T Prime GR1 USCA-XXMB-0316-PGE USCA-XXMB-0316-PGE
E-6 Choice Flat USCA-XXMB-0317-PGE USCA-XXMB-0317-PGE
E-6 Choice GR1 USCA-XXMB-0318-PGE USCA-XXMB-0318-PGE
E-6 Prime Flat USCA-XXMB-0319-PGE USCA-XXMB-0319-PGE
E-6 Prime GR1 USCA-XXMB-0320-PGE USCA-XXMB-0320-PGE
E-ELEC Choice Flat USCA-XXMB-0321-PGE USCA-XXMB-0321-PGE E-ELEC Choice GR1 USCA-XXMB-0322-PGE USCA-XXMB-0322-PGE E-ELEC Prime Flat USCA-XXMB-0323-PGE USCA-XXMB-0323-PGE E-ELEC Prime GR1 USCA-XXMB-0324-PGE USCA-XXMB-0324-PGE
30 E-EV Choice Flat USCA-XXMB-0325-PGE USCA-XXMB-0325-PGE E-EV Choice GR1 USCA-XXMB-0326-PGE USCA-XXMB-0326-PGE
E-EV Prime Flat USCA-XXMB-0327-PGE USCA-XXMB-0327-PGE
E-EV Prime GR1 USCA-XXMB-0328-PGE USCA-XXMB-0328-PGE
E-EV2-A Choice Flat USCA-XXMB-0329-PGE USCA-XXMB-0329-PGE E-EV2-A Choice GR1 USCA-XXMB-0330-PGE USCA-XXMB-0330-PGE E-EV2-A Prime Flat USCA-XXMB-0331-PGE USCA-XXMB-0331-PGE E-EV2-A Prime GR1 USCA-XXMB-0332-PGE USCA-XXMB-0332-PGE E-TOU-B Choice Flat USCA-XXMB-0333-PGE USCA-XXMB-0333-PGE E-TOU-B Choice GR1 USCA-XXMB-0334-PGE USCA-XXMB-0334-PGE E-TOU-B Prime Flat USCA-XXMB-0335-PGE USCA-XXMB-0335-PGE E-TOU-B Prime GR1 USCA-XXMB-0336-PGE USCA-XXMB-0336-PGE E-TOU-C Choice Flat USCA-XXMB-0337-PGE USCA-XXMB-0337-PGE E-TOU-C Choice GR1 USCA-XXMB-0338-PGE USCA-XXMB-0338-PGE E-TOU-C Prime Flat USCA-XXMB-0339-PGE USCA-XXMB-0339-PGE E-TOU-C Prime GR1 USCA-XXMB-0340-PGE USCA-XXMB-0340-PGE E-TOU-D Choice Flat USCA-XXMB-0341-PGE USCA-XXMB-0341-PGE E-TOU-D Choice GR1 USCA-XXMB-0342-PGE USCA-XXMB-0342-PGE E-TOU-D Prime Flat USCA-XXMB-0343-PGE USCA-XXMB-0343-PGE E-TOU-D Prime GR1 USCA-XXMB-0344-PGE USCA-XXMB-0344-PGE S-B-P Choice Flat USCA-XXMB-0345-PGE USCA-XXMB-0345-PGE S-B-P Choice GR1 USCA-XXMB-0346-PGE USCA-XXMB-0346-PGE
S-B-P Prime Flat USCA-XXMB-0347-PGE USCA-XXMB-0347-PGE
S-B-P Prime GR1 USCA-XXMB-0348-PGE USCA-XXMB-0348-PGE
S-B-S Choice Flat USCA-XXMB-0349-PGE USCA-XXMB-0349-PGE S-B-S Choice GR1 USCA-XXMB-0350-PGE USCA-XXMB-0350-PGE
S-B-S Prime Flat USCA-XXMB-0351-PGE USCA-XXMB-0351-PGE
S-B-S Prime GR1 USCA-XXMB-0352-PGE USCA-XXMB-0352-PGE
S-B-T Choice Flat USCA-XXMB-0353-PGE USCA-XXMB-0353-PGE S-B-T Choice GR1 USCA-XXMB-0354-PGE USCA-XXMB-0354-PGE
S-B-T Prime Flat USCA-XXMB-0355-PGE USCA-XXMB-0355-PGE
S-B-T Prime GR1 USCA-XXMB-0356-PGE USCA-XXMB-0356-PGE
S-TOU-P Choice Flat USCA-XXMB-0357-PGE USCA-XXMB-0357-PGE S-TOU-P Choice GR1 USCA-XXMB-0358-PGE USCA-XXMB-0358-PGE S-TOU-P Prime Flat USCA-XXMB-0359-PGE USCA-XXMB-0359-PGE S-TOU-P Prime GR1 USCA-XXMB-0360-PGE USCA-XXMB-0360-PGE S-TOU-S Choice Flat USCA-XXMB-0361-PGE USCA-XXMB-0361-PGE S-TOU-S Choice GR1 USCA-XXMB-0362-PGE USCA-XXMB-0362-PGE S-TOU-S Prime Flat USCA-XXMB-0363-PGE USCA-XXMB-0363-PGE S-TOU-S Prime GR1 USCA-XXMB-0364-PGE USCA-XXMB-0364-PGE S-TOU-T Choice Flat USCA-XXMB-0365-PGE USCA-XXMB-0365-PGE
31 S-TOU-T Choice GR1 USCA-XXMB-0366-PGE USCA-XXMB-0366-PGE S-TOU-T Prime Flat USCA-XXMB-0367-PGE USCA-XXMB-0367-PGE S-TOU-T Prime GR1 USCA-XXMB-0368-PGE USCA-XXMB-0368-PGE AL-2-GF USCA-XXMB-0001-SCE USCA-XXMB-0001-SCE
TOU-8-PRI-B USCA-XXMB-0002-SCE USCA-XXMB-0002-SCE
TOU-8-PRI-D USCA-XXMB-0003-SCE USCA-XXMB-0003-SCE
TOU-8-PRI-E USCA-XXMB-0004-SCE USCA-XXMB-0004-SCE
TOU-8-PRI-R USCA-XXMB-0005-SCE USCA-XXMB-0005-SCE
TOU-8-PRI-RBU USCA-XXMB-0006-SCE USCA-XXMB-0006-SCE
TOU-8-SEC-B USCA-XXMB-0007-SCE USCA-XXMB-0007-SCE
TOU-8-SEC-D USCA-XXMB-0008-SCE USCA-XXMB-0008-SCE
TOU-8-SEC-E USCA-XXMB-0009-SCE USCA-XXMB-0009-SCE
TOU-8-SEC-R USCA-XXMB-0010-SCE USCA-XXMB-0010-SCE
TOU-8-SEC-RBU USCA-XXMB-0011-SCE USCA-XXMB-0011-SCE
TOU-8-SUB-B USCA-XXMB-0012-SCE USCA-XXMB-0012-SCE
TOU-8-SUB-D USCA-XXMB-0013-SCE USCA-XXMB-0013-SCE
TOU-8-SUB-E USCA-XXMB-0014-SCE USCA-XXMB-0014-SCE
TOU-8-SUB-R USCA-XXMB-0015-SCE USCA-XXMB-0015-SCE
TOU-8-SUB-RBU USCA-XXMB-0016-SCE USCA-XXMB-0016-SCE
TOU-8-TRS-B USCA-XXMB-0017-SCE USCA-XXMB-0017-SCE
TOU-8-TRS-D USCA-XXMB-0018-SCE USCA-XXMB-0018-SCE
TOU-8-TRS-E USCA-XXMB-0019-SCE USCA-XXMB-0019-SCE
TOU-8-TRS-R USCA-XXMB-0020-SCE USCA-XXMB-0020-SCE
TOU-8-TRS-RBU USCA-XXMB-0021-SCE USCA-XXMB-0021-SCE
TOU-D-4 USCA-XXMB-0022-SCE USCA-XXMB-0022-SCE
TOU-D-5 USCA-XXMB-0023-SCE USCA-XXMB-0023-SCE
TOU-D-A USCA-XXMB-0024-SCE USCA-XXMB-0024-SCE
TOU-D-B USCA-XXMB-0025-SCE USCA-XXMB-0025-SCE
TOU-D-PRIME USCA-XXMB-0026-SCE USCA-XXMB-0026-SCE
TOU-D-T USCA-XXMB-0027-SCE USCA-XXMB-0027-SCE
TOU-EV-1 USCA-XXMB-0028-SCE USCA-XXMB-0028-SCE
TOU-EV-7-PRI USCA-XXMB-0029-SCE USCA-XXMB-0029-SCE
TOU-EV-7-SEC USCA-XXMB-0030-SCE USCA-XXMB-0030-SCE
TOU-EV-7-SUB USCA-XXMB-0031-SCE USCA-XXMB-0031-SCE
TOU-EV-7-TRS USCA-XXMB-0032-SCE USCA-XXMB-0032-SCE
TOU-EV-8-PRI USCA-XXMB-0033-SCE USCA-XXMB-0033-SCE
TOU-EV-8-SEC USCA-XXMB-0034-SCE USCA-XXMB-0034-SCE
TOU-EV-8-SUB USCA-XXMB-0035-SCE USCA-XXMB-0035-SCE
TOU-EV-8-TRS USCA-XXMB-0036-SCE USCA-XXMB-0036-SCE
TOU-EV-9-PRI USCA-XXMB-0037-SCE USCA-XXMB-0037-SCE
TOU-EV-9-SEC USCA-XXMB-0038-SCE USCA-XXMB-0038-SCE
32 TOU-EV-9-SUB USCA-XXMB-0039-SCE USCA-XXMB-0039-SCE
TOU-EV-9-TRS USCA-XXMB-0040-SCE USCA-XXMB-0040-SCE
TOU-GS-1-A USCA-XXMB-0041-SCE USCA-XXMB-0041-SCE
TOU-GS-1-B USCA-XXMB-0042-SCE USCA-XXMB-0042-SCE
TOU-GS-1-PRI-D USCA-XXMB-0043-SCE USCA-XXMB-0043-SCE
TOU-GS-1-PRI-E USCA-XXMB-0044-SCE USCA-XXMB-0044-SCE
TOU-GS-1-PRI-ES USCA-XXMB-0045-SCE USCA-XXMB-0045-SCE
TOU-GS-1-SEC-D USCA-XXMB-0046-SCE USCA-XXMB-0046-SCE
TOU-GS-1-SEC-E USCA-XXMB-0047-SCE USCA-XXMB-0047-SCE
TOU-GS-1-SEC-ES USCA-XXMB-0048-SCE USCA-XXMB-0048-SCE
TOU-GS-1-SUB-D USCA-XXMB-0049-SCE USCA-XXMB-0049-SCE
TOU-GS-1-SUB-E USCA-XXMB-0050-SCE USCA-XXMB-0050-SCE
TOU-GS-1-SUB-ES USCA-XXMB-0051-SCE USCA-XXMB-0051-SCE
TOU-GS-1-TRS-D USCA-XXMB-0052-SCE USCA-XXMB-0052-SCE
TOU-GS-1-TRS-E USCA-XXMB-0053-SCE USCA-XXMB-0053-SCE
TOU-GS-1-TRS-ES USCA-XXMB-0054-SCE USCA-XXMB-0054-SCE
TOU-GS-2-B USCA-XXMB-0055-SCE USCA-XXMB-0055-SCE
TOU-GS-2-PRI-D USCA-XXMB-0056-SCE USCA-XXMB-0056-SCE
TOU-GS-2-PRI-E USCA-XXMB-0057-SCE USCA-XXMB-0057-SCE
TOU-GS-2-R USCA-XXMB-0058-SCE USCA-XXMB-0058-SCE
TOU-GS-2-SEC-D USCA-XXMB-0059-SCE USCA-XXMB-0059-SCE
TOU-GS-2-SEC-E USCA-XXMB-0060-SCE USCA-XXMB-0060-SCE
TOU-GS-2-SUB-D USCA-XXMB-0061-SCE USCA-XXMB-0061-SCE
TOU-GS-2-SUB-E USCA-XXMB-0062-SCE USCA-XXMB-0062-SCE
TOU-GS-2-TRS-D USCA-XXMB-0063-SCE USCA-XXMB-0063-SCE
TOU-GS-2-TRS-E USCA-XXMB-0064-SCE USCA-XXMB-0064-SCE
TOU-GS-3-B USCA-XXMB-0065-SCE USCA-XXMB-0065-SCE
TOU-GS-3-PRI-D USCA-XXMB-0066-SCE USCA-XXMB-0066-SCE
TOU-GS-3-PRI-E USCA-XXMB-0067-SCE USCA-XXMB-0067-SCE
TOU-GS-3-R USCA-XXMB-0068-SCE USCA-XXMB-0068-SCE
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34 TOU-8-SEC-RBU-3Cprime USCA-XXMB-0121-SCE USCA-XXMB-0121-SCE TOU-8-SUB-B-3Cprime USCA-XXMB-0122-SCE USCA-XXMB-0122-SCE TOU-8-SUB-D-3Cprime USCA-XXMB-0123-SCE USCA-XXMB-0123-SCE TOU-8-SUB-E-3Cprime USCA-XXMB-0124-SCE USCA-XXMB-0124-SCE TOU-8-SUB-R-3Cprime USCA-XXMB-0125-SCE USCA-XXMB-0125-SCE TOU-8-SUB-RBU-3CprimeUSCA-XXMB-0126-SCE USCA-XXMB-0126-SCE TOU-8-TRS-B-3Cprime USCA-XXMB-0127-SCE USCA-XXMB-0127-SCE TOU-8-TRS-D-3Cprime USCA-XXMB-0128-SCE USCA-XXMB-0128-SCE TOU-8-TRS-E-3Cprime USCA-XXMB-0129-SCE USCA-XXMB-0129-SCE TOU-8-TRS-R-3Cprime USCA-XXMB-0130-SCE USCA-XXMB-0130-SCE TOU-8-TRS-RBU-3Cprime USCA-XXMB-0131-SCE USCA-XXMB-0131-SCE TOU-D-4-3Cprime USCA-XXMB-0132-SCE USCA-XXMB-0132-SCE
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35 TOU-GS-1-SEC-ES-3CprimeUSCA-XXMB-0158-SCE USCA-XXMB-0158-SCE TOU-GS-1-SUB-D-3CprimeUSCA-XXMB-0159-SCE USCA-XXMB-0159-SCE TOU-GS-1-SUB-E-3CprimeUSCA-XXMB-0160-SCE USCA-XXMB-0160-SCE TOU-GS-1-SUB-ES-3CprimeUSCA-XXMB-0161-SCE USCA-XXMB-0161-SCE TOU-GS-1-TRS-D-3CprimeUSCA-XXMB-0162-SCE USCA-XXMB-0162-SCE TOU-GS-1-TRS-E-3CprimeUSCA-XXMB-0163-SCE USCA-XXMB-0163-SCE TOU-GS-1-TRS-ES-3CprimeUSCA-XXMB-0164-SCE USCA-XXMB-0164-SCE TOU-GS-2-B-3Cprime USCA-XXMB-0165-SCE USCA-XXMB-0165-SCE TOU-GS-2-PRI-D-3Cprime USCA-XXMB-0166-SCE USCA-XXMB-0166-SCE TOU-GS-2-PRI-E-3Cprime USCA-XXMB-0167-SCE USCA-XXMB-0167-SCE TOU-GS-2-R-3Cprime USCA-XXMB-0168-SCE USCA-XXMB-0168-SCE TOU-GS-2-SEC-D-3CprimeUSCA-XXMB-0169-SCE USCA-XXMB-0169-SCE TOU-GS-2-SEC-E-3CprimeUSCA-XXMB-0170-SCE USCA-XXMB-0170-SCE TOU-GS-2-SUB-D-3CprimeUSCA-XXMB-0171-SCE USCA-XXMB-0171-SCE TOU-GS-2-SUB-E-3CprimeUSCA-XXMB-0172-SCE USCA-XXMB-0172-SCE TOU-GS-2-TRS-D-3CprimeUSCA-XXMB-0173-SCE USCA-XXMB-0173-SCE TOU-GS-2-TRS-E-3CprimeUSCA-XXMB-0174-SCE USCA-XXMB-0174-SCE TOU-GS-3-B-3Cprime USCA-XXMB-0175-SCE USCA-XXMB-0175-SCE TOU-GS-3-PRI-D-3Cprime USCA-XXMB-0176-SCE USCA-XXMB-0176-SCE TOU-GS-3-PRI-E-3Cprime USCA-XXMB-0177-SCE USCA-XXMB-0177-SCE TOU-GS-3-R-3Cprime USCA-XXMB-0178-SCE USCA-XXMB-0178-SCE TOU-GS-3-SEC-D-3CprimeUSCA-XXMB-0179-SCE USCA-XXMB-0179-SCE TOU-GS-3-SEC-E-3CprimeUSCA-XXMB-0180-SCE USCA-XXMB-0180-SCE TOU-GS-3-SUB-D-3CprimeUSCA-XXMB-0181-SCE USCA-XXMB-0181-SCE TOU-GS-3-SUB-E-3CprimeUSCA-XXMB-0182-SCE USCA-XXMB-0182-SCE TOU-GS-3-TRS-D-3CprimeUSCA-XXMB-0183-SCE USCA-XXMB-0183-SCE TOU-GS-3-TRS-E-3CprimeUSCA-XXMB-0184-SCE USCA-XXMB-0184-SCE
36 TOU-PA-2-A-3Cprime USCA-XXMB-0185-SCE USCA-XXMB-0185-SCE TOU-PA-2-B-3Cprime USCA-XXMB-0186-SCE USCA-XXMB-0186-SCE TOU-PA-2-PRI-D-3CprimeUSCA-XXMB-0187-SCE USCA-XXMB-0187-SCE TOU-PA-2-PRI-D5-
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37 TOU-PA-3-SEC-E-3CprimeUSCA-XXMB-0211-SCE USCA-XXMB-0211-SCE TOU-PA-3-SEC-E5-
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Staff Report Item 6
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Kalia Mitchell-Silbaugh, Policy Advisor;
Jerri Strickland, Policy Advisor;
Catherine Stedman, Chief Communication Officer
SUBJECT: Receive Regulatory and Legislative Quarterly Update DATE: February 21, 2023
RECOMMENDATION:
This recommends the Policy Board receive the attached 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.
Quarterly Regulatory & Legislative Update
February 21, 2024
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 Demand Flexibility............................................................................................................................................................. 4 Preventing Disconnections............................................................................................................................................. 5 Bioenergy Market Adjustment Tariff (BioMAT).................................................................................................... 5 Integrated Resource Planning (IRP)........................................................................................................................... 6 GO 156 Annual Supplier Diversity Report & Plan................................................................................................. 6 Affordability.......................................................................................................................................................................... 7 PG&E Helms Uprate Application.................................................................................................................................. 7 Renewables Portfolio Standard.................................................................................................................................... 7 Interconnections................................................................................................................................................................. 8 Diablo Canyon Power Plant Extension ...................................................................................................................... 8 Energy Resources Recovery Account (ERRA) Compliance ............................................................................... 9 Energy Resources Recovery Account (ERRA) Forecast....................................................................................10 LEGISLATIVE UPDATE........................................................................................................................................................10
REGULATORY UPDATE
Resource Adequacy (RA)
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
The CPUC opened a new RA proceeding at the end of 2023 that will prioritize refining the new slice-of-day (SOD) framework for the 2025 RA compliance year.
Next Steps
CalCCA submitted a reform proposal on January 19th seeking to stabilize the RA market, reign in prices, and encourage out of state participation in the California RA market. If accepted, the recommendations would help ensure a smooth transition through the first SOD RA framework compliance year. A PD on party proposals is expected in May.
Provider of Last Resort (POLR) and Emergency Transition Planning 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.
This proceeding is also considering 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). 3CE’s FSR has been set at $147,000 since 2018, but that amount is likely to increase with the reforms being considered in this proceeding.
Status
In July of 2023, parties including CalCCA filed opening and reply briefs. This was the last opportunity for stakeholder input before the CPUC issues a Proposed Decision on FSR changes.
Next Steps
Staff are still awaiting issuance of the delayed October 2023 Proposed Decision (PD). On February 7th, 3CE Staff met with Energy Division staff to request a status update on this proceeding. When published, staff will analyze the PD, provide feedback through comments, and hold meetings with CPUC staff as appropriate. Additionally, 3CE will incorporate any FSR changes into internal financial planning.
Load Management Standards (LMS) and Real-Time Pricing
Issue
The California Energy Commission’s (CEC) updated Load Management Standards (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, submit an LMS Compliance Plan by April 2024, and obtain approval from 3CE’s rate setting board.
Status
As of July 28, 2023, 3CE’s MIDAS platform updates have been completed.
Next Steps
3CE staff are presenting today via separate agenda item 3CE’s LMS Compliance Plan for approval and submission to the CEC.
Demand Flexibility
Issue
The CPUC opened this proceeding in 2022 to promote demand flexibility in California in order to improve grid reliability and reduce the cost of grid stress events. While this proceeding does not directly govern CCA ratemaking, 3CE is participating to ensure CCA ratemaking authority is preserved, monitor changes to IOU transmission and distribution rates, address data access issues between IOUs and CCAs that hinder time-dependent rate design, and help prevent cost shifts between bundled and unbundled customers.
This proceeding is also implementing the requirement set by AB 205 in 2022 that the CPUC design an income-graduated fixed charge (IGFC) for all residential electric utility customers by July 1, 2024. The goal is to reduce energy costs for low-income Californians by creating a monthly fixed charge that increases with income, allowing the per-kWh volumetric charge to be lower. While the fixed charge will be on the delivery side of the bill and not affect 3CE operations directly, 3CE staff are following the process to understand how customers’ experience will evolve around 3CE service.
Status
On January 26, the CPUC issued a Decision directing PG&E to expand CCA Valley Clean Energy’s AgFit pilot to bundled and unbundled agricultural customers in PG&E service territory and extending the duration of the pilot to December 31, 2027. AgFit offers agricultural customers assistance with water pumping automation, time-varying rates that incentivize pumping during off-peak hours, and on-bill savings. The Decision authorizes funding for PG&E to administer the expanded pilot and provide incentives to CCAs for pilot participation.
Next Steps
3CE program staff are actively evaluating AgFIT participation which will provide dynamic pricing to encourage irrigation in solar generation hours, when prices, and emissions, are lower. 3CE will continue to monitor the implementation of the first IGFCs to ensure that fixed charges are limited to transmission and distribution rate components and will analyze the PD on the IGFC upon its issuance, scheduled for March or April of 2024.
Preventing Disconnections
Issue
In June 2020, the CPUC created the Arrearage Management Program (AMP) to help vulnerable Californians, including CCA customers, manage overdue electricity bills and avoid disconnection. For eligible customers, the program forgives 1/12 of the customer’s debt for every on-time payment of a current bill, up to $8,000 per customer after twelve on-time payments. Customer debt that is forgiven through the program is paid to 3CE and other load-serving entities out of funds collected from all electricity customers through the Public Purpose Programs charge. The AMP program was originally set to sunset after four years in June 2024.
Status
On August 31, 2023, the CPUC approved a Decision extending both AMP and Long-Term Payment Plans for eligible residential customers until October 1, 2026; requiring an AMP evaluation by October 1, 2025; and authorizing a study of medical baseline programs for each IOU service territory. The CPUC also issued a Proposed Decision on January 9th that approves the CBO Arrears Case Management Pilot Program, which provides grants to CBOs that enroll customers in case management services.
Next Steps
The AMP program will now be available to 3CE customers through 2026 without interruption. The CPUC is reviewing additional solutions for reducing disconnection rates, including long-term payment plans, a proposed study of the Medical Baseline population, and the future of the Percentage of Income Payment Plan (PIPP) program. 3CE will continue to advocate for policies that prioritize customer connectivity and establish a streamlined process for fast reconnection to ensure that customers remain connected to essential services.
Bioenergy Market Adjustment Tariff (BioMAT)
Issue
BioMAT is a procurement program opened in 2015 to encourage the development of small bioenergy projects in California. The program is unique in that it allows load serving entities (LSEs) contracting with these projects to recover the costs from all California electricity users through the Public Purpose Programs (PPP) charge. In 2021 3CE and other CCAs successfully lobbied legislators to reverse the exclusion of CCAs from BioMAT with the passage of AB 843. AB 843 was the first time CCAs gained access to PPP funding, setting a valuable policy precedent. The CPUC began implementation of AB 843 in October 2022 by opening of a new proceeding to work through the details of CCA participation.
Status
On January 29, CalCCA submitted a BioMAT program enrollment Advice Letter (AL) on behalf of participating CCAs, including 3CE, requesting approval of pro forma program documents. On February 1, 3CE submitted a Tier 3 AL stating that there were no forecasted BioMAT revenue requirements as currently no eligible Power Purchase Agreements have been signed for 2024-2025.
Next Steps
3CE is working internally to set up a balancing account to track BioMAT program costs for reimbursement by the CPUC, as well as other implementation steps in preparation to utilize the BioMAT program throughout its sunset date of December 31, 2025.
Integrated Resource Planning (IRP)
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 while maintaining grid reliability. Previous IRP cycles have produced three procurement mandates, which apply to 3CE and other CCAs. The next cycle of IRP will begin shortly.
Status
The CPUC issued a Proposed Decision on January 10 that evaluates the 2022 IRP filings of all LSEs, adopts a Preferred System Plan (PSP) portfolio that meets a statewide 25 million metric ton GHG target for the electric sector in 2035, and approves with modifications a Petition for Modification (PFM) to allow extension of deadlines for procurement of long lead-time (LLT) resources when certain conditions are met. 3CE previously submitted comments in support of the PFM because it aligns with the goal of accelerating LLT resource deployment and decreases the likelihood that a LSE will be penalized for delays outside of its control. This decision also approved or requested additional information on individual LSE’s 2022 IRP submissions. 3CE was requested to provide additional information on our rate design by May 1, 2024.
Next Steps
Staff are already readying a response to the request for additional information highlighting our progressing cost-of-service rate structure and how it minimizes bill impacts for customers, this will be provided to the CPUC well before the May 1 deadline. Additionally, 3CE will be actively engaged in this proceeding, conducting advocacy around the structure of the long-term framework, and incorporating any new mandates or changes to previous ones into internal procurement planning. The next round of IRP submissions will be due November 2024.
GO 156 Annual Supplier Diversity Report & Plan
Issue
GO 156 is a California Public Utilities Commission (CPUC) program that requires California load-serving entities to report on the portion of their contracts and subcontracts that are signed with businesses that qualify as Women, Minority, Disabled, Veteran, Lesbian, Gay, Bisexual, Transgender Business Enterprises (WMDVLGBTBE).
Status
On September 21, 2023, the CPUC issued a Decision extending the statutory deadline for this proceeding to September 17, 2024, to further consider revisions to GO 156 reporting requirements.
Next Steps
Pursuant to GO 156, 3CE Staff have begun working on the 2023 Annual Supplier Diversity Report and 2024 Plan and will submit it to the CPUC by March 1, 2024. The content will present 3CE’s 2023 annual non-energy spending and planned activities to support small, local, and diverse businesses in 2024. This will be 3CE’s fourth iteration of the report. As done in previous submissions, staff will highlight how equity is priority of our board decisions and organizational practices.
Affordability
Issue
In 2018, the CPUC opened a Rulemaking to develop tools to assess affordability across CPUC proceedings and utility rate requests. To date, the proceeding has established that the CPUC will annually update its affordability framework based on data from utility bills and from the US. Census Bureau on income and housing costs. The affordability framework consists of metrics, an Affordability Ratio Calculator, maps, quarterly utility revenue reports, and annual affordability reports.
Status
The statutory deadline for the Affordability proceeding has been extended to December 1, 2024, to conclude assessment of the CPUC’s implementation of its affordability framework and incorporate refinement. CalCCA submitted comments in response to a December 13th Ruling requesting feedback to recommend that the CPUC require implementation of the framework in non-ratesetting proceedings that impact rates, including the Demand Flexibility, RA, and IRP proceedings, and increased transparency with how the CPUC utilizes affordability metrics in decision-making.
Next Steps
3CE will continue to monitor this proceeding and advocate for effective use of affordability metrics across regulatory activities to ensure cost considerations are integrated into decision-making processes.
PG&E Helms Uprate Application
Issue
On December 20, 2023, PG&E filed an application proposing to increase capacity of the existing Helms Pumped Storage Facility by 150-180 MW and to attribute incremental costs to a new PCIA vintage while keeping any costs associated with maintaining the original capacity at Helms in its original PCIA vintage.
This Application raises critical PCIA vintaging issues and has the potential to significantly impact the CPUC’s evolving vintaging policy for utility re-investments in utility-owned generation (UOG).
Status
On January 22, CalCCA submitted a protest to the Application to express its high-level interest in ensuring the cost recovery mechanism approved for this Application is just, reasonable, and consistent with best practices for allocating costs associated with significant re-investments in UOG.
Next Steps
3CE staff is actively working with CalCCA to analyze PG&E’s proposal, consider potential approaches to re-vintaging, and determine the most fair and beneficial method for cost allocation between bundled and unbundled customers.
Renewables Portfolio Standard
Issue
The CPUC’s Renewables Portfolio Standard (RPS) proceeding monitors compliance by retail sellers, including CCAs, within California’s RPS program which requires that 60% of all electricity retail sales be served by renewable resources by 2030 and at least 65% of the procurement a retail seller counts toward the RPS requirements be from long-term contracts.
Status
On December 21, the CPUC issued a Decision adopting the Draft 2023 RPS plans of retail sellers including 3CE. On January 25, the CPUC voted to initiate a new rulemaking to continue implementation of the RPS program, including reviewing RPS procurement plans, providing tools for RPS analysis and reporting, assessing RPS compliance, and integrating new legislative mandates into the RPS program.
Next Steps
Staff will actively monitor and participate in the new RPS proceeding, advocating for the use of appropriate tools and analysis to enhance the reporting process by the CPUC. Meanwhile, 3CE will maintain its commitment to ongoing RPS compliance, aligning with the Board's directive to surpass the state's goal well in advance by procuring 100% clean and renewable energy by 2030.
Interconnections
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. In addition, the CPUC instituted a new rulemaking in January of 2024 to establish reasonable timelines for customers to receive new service connections and to create procedures for customers to report delays as part of implementing recent statutes.
Status
The CPUC will host an opening workshop in February and issue a scoping memo in March for its new OIR.
CAISO released an IPE proposal on December 12th to further define its zonal approach to interconnection management, which encourages interconnections in transmission zones with available and approved transmission capacity, and its scoring criteria for evaluating readiness of interconnection requests.
CalCCA submitted comments in support of the revised proposal. CAISO will host a meeting later this month to discuss its forthcoming draft final proposal.
Next Steps
Distribution planning or implementation failures can delay new customer load interconnection, affecting CCA customers. 3CE will continue to monitor these initiatives, advocate for transparency and efficiency in interconnection and energization processes, and promote accelerated deployment and grid connection of clean energy resources.
Diablo Canyon Power Plant Extension
Issue
Senate Bill (SB) 846 required the CPUC to consider the potential expansion of operations at the Diablo Canyon Power Plant (DCPP) for an additional five years beyond its retirement dates to improve system reliability while additional renewable energy and zero-carbon resources come online. DCPP is owned and operated by PG&E and was licensed by the Nuclear Regulatory Commission (NRC) to operate until November 2, 2024 (Unit 1) and August 26, 2025 (Unit 2). In 2023, the CPUC opened a new proceeding related to the potential extension of DCPP.
Status
On December 14th, the CPUC issued Decision D.23-12-036, approving extended operations at DCPP under certain conditions. The decision is contingent on NRC authorization, the continuation of the loan agreement authorized by SB 846, and the absence of a future CPUC determination that DCPP operations are imprudent. This decision also allocates costs and benefits, introduces a new non-bypassable charge for DCPP extended operations costs, and establishes a review process akin to annual ERRA proceedings.
On January 16, PG&E filed an Application for Rehearing of D.23-12-036, contesting the requirement for prior Commission approval of PG&E's earned operating-risk compensation expenditures and the mandate to apply operating-risk compensation to offset Diablo Canyon's operating costs exceeding 115% of forecast costs.
Next Steps
The Decision permits each IOU to employ a process resembling the Cost Allocation Mechanism (CAM) to distribute DCPP extended costs and Resource Adequacy (RA) benefits to Load Serving Entities (LSEs) within its service area. PG&E is set to submit the initial DCPP Extended Operations Cost Forecast application in March, covering projected costs through December 2025. 3CE will closely monitor PG&E's Application for Rehearing to stay informed about any modifications that may affect 3CE.
Energy Resources Recovery Account (ERRA) Compliance
Issue
Energy Resource Recovery Account (ERRA) compliance filings are made annually by the Investor Owned Utilities (IOUs) for the approval of costs associated with Utility Owned Generation (UOG) operations and fuel procurement, Portfolio Allocation Balancing Account (PABA) entries, economic dispatch of electric resources, and contract administration. IOUs are required to demonstrate compliance with CPUC decisions and the California Public Utilities Code. All CCAs participate jointly in these proceedings through CalCCA to ensure unbundled customers are treated equitably in IOU rate-setting decisions.
PG&E Status
On January 11, 2024, during PG&E's 2022 ERRA Compliance case prehearing conference, PG&E moved to strike portions of the CalCCA expert witness' testimony regarding compliance with excess RA availability.
PG&E argued it followed the Bundled Procurement Plan, while the expert witness contended compliance included adhering to D.21-12-015, requiring reasonable attempts to sell excess RA. In 2022, PG&E initially didn't show excess RA during quarterly offerings but later revealed over 900MW. The ALJ will weigh PG&E's motion during CalCCA's evidence admission motion. On January 18, 2024, CalCCA submitted motions related to evidence admission, but on January 23, the ALJ granted PG&E's motion to strike sections of the expert witness’ testimony without providing reasoning.
SCE Status
On January 5, 2024, an Amended Scoping Ruling for SCE’s 2022 ERRA Compliance case introduced Scoping Issue 8, without modifying the schedule outlined in the August 11, 2023, Scoping Ruling. Scoping Issue 8 pertains to SCE's operation of memorandum and balancing accounts during the 2022 Record Period, assessing the appropriateness, correctness, and compliance of recorded entries with Commission decisions.
Next Steps
The Joint CCAs are strategizing for response, with PG&E’s hearings are scheduled for late February and SCE will be filing Rebuttal Testimony by January 31st. 3CE will continue to advocate for just treatment of unbundled customers and hold the IOUs accountable for following CPUC rules.
Energy Resources Recovery Account (ERRA) Forecast
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.
Status
On January 5, 2024, CalCCA, SDCP, and CEA (CCA Parties) submitted a pre-hearing conference (PHC) statement for the January 9 PHC regarding the Track 2 ERRA Forecast proceeding. Track 2, involving all three IOUs, focuses on fixed generation costs. Diverse determinations by IOUs on these costs were revealed through ERRA forecast rulings. The PHC statement includes recommendations on scope and schedule, emphasizing issues like utility-owned generation vintaging, treatment of banked RECs, and excluding Replacement RA costs. During the January 9 PHC, the CCA Parties presented these concerns, with Cal Advocates supporting the call for a standardized definition of fixed generation costs.
Next Steps
The ALJ will make decisions on scoping rulings, including issues like UOG revintaging and banked REC treatment. The inclusion of these issues may impact the valuation of PCIA, potentially resulting in benefits or drawbacks for unbundled customers. The CCAs will continue to review the work presented by the IOUs to ensure the just treatment of both bundled and unbundled customers.
LEGISLATIVE UPDATE
California’s 2024 legislative session got underway on January 3, with a February 16 deadline set in both the Assembly and the Senate for the introduction of new bills.
On January 10, Governor Newsom presented his state budget proposal to the legislature, projecting a $38 billion shortfall, and proposing to close the gap through reserves, delays and deferrals of previously authorized spending, and spending cuts. The Governor’s proposal keeps $48.3 million in climate budget, but spreads it over seven rather than five years, while asserting an additional $10 billion in federal funding that will be available to the state for climate related programs. Revisions to the budget are expected in May from the Governor. Between now and then, the legislature will deliberate on the proposal, likely providing adjustments before going into negotiations to produce an agreed upon state budget by the Constitutional deadline of June 15th .
3CE and CalCCA have identified a number of proposed policies with potential impacts to Community Choice Aggregators, including bills concerning renewable hydrogen, GHG emissions reporting, the Public Records Act, and investor-owned utility (IOU) political spending.
CCAs are also tracking bill proposals from various demand response and renewable energy project developers, now in search of authors, that aim to advance virtual power plants, which are defined as the collective management of energy to support grid needs through thermostats, EVs, appliances, batteries, and solar arrays.
In addition, there is continued monitoring of the California Climate and Flood Protection Bond Measure, which is still being hotly negotiated amongst stakeholders and the legislature. Efforts introduced last year have yet to be sent to the Governor’s desk – a needed step to make it to the November ballot.
Given concerns about servicing additional debt during a fiscal downturn, the final amount of the bond may be significantly less than the current $15 billion proposal.
At this stage in the session, the bills of greatest interest are:
AB 1999 (Irwin): Income graduated fixed charge repeal: This bill seeks to repeal AB 205, passed in 2022, which authorized the California Public Utilities Commission (CPUC) to restructure energy rates so that a larger portion of costs would be collected through fixed charges based on income. While the intention was to spread costs more equitably, IOU proposals have raised concerns the policy would backfire in practice by increasing customer arrearages and discouraging electrification. AB 1999’s authors include Central Coast Assembly Members Dawn Addis and Gail Pellerin.
SB 1003 (Dodd): Safe, timely and affordable infrastructure upgrades and SB 1006 (Padilla):
Reconductoring and grid enhancing technologies: These bills seek to impose timelines on IOU electrical infrastructure upgrades and compel the evaluation of alternatives to undergrounding, such as the insulating of existing utility cable, in the interest of achieving time and cost savings.
During last year’s session, AB 538 (Holden) – which would have enabled CAISO’s independent governance board to change to a regional transmission operator – failed. California regulators and stakeholders are now working on regionalization with others in the west through the West-Wide Governance Pathways Initiative. Reporting on all that is happening under the initiative can be found here.
Finally, 3CE is taking part in CalCCA’s Lobby Day, held in Sacramento on February 20, and is actively scheduling in-district meetings with local legislators to discuss priorities for the session, challenges facing CCAs, and provide updates on the agency’s accomplishments in renewable energy procurement and community energy program participation.
Staff Report Item 7
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Paige Callaghan, Energy Programs Analyst
SUBJECT: Receive Update on FY 2023-24 Energy Programs
DATE: February 21, 2024
RECOMMENDATION:
This memorandum recommends the Policy Board of Directors receive an update on 3CE’s FY 2023- 24 Energy Programs.
DISCUSSION/ANALYSIS:
Attached to this report are status updates on 3CE’s Energy Programs, including both Community Programs (Attachment 1) and Member Agency Programs (Attachment 2). These status updates highlight a variety of program performance metrics, such as equipment incentivized, housing units electrified, dollars spent, and resources allocated to income qualified residents.
FISCAL IMPACT:
There is no fiscal impact associated with this report and update.
CONCLUSION:
3CE’s Energy Programs help reduce GHG emission and support local economic stimulation by providing the community and Member Agencies with support and financial incentives to accelerate regional electrification.
ATTACHMENT(S):
1. Community Energy Programs Update
2. Member Agency Services Update
2023-24 3CE Community Energy Programs
This report provides an update on Central Coast Community Energy’s (3CE) FY 2023-24 Community Energy Programs.
New Construction Electrification Program
3CE’s New Construction Electrification Program (NCEP) provides incentives to build all-electric housing for developers of affordable and farmworker housing, homeowners building Accessory Dwelling Units (ADUs), and homeowners rebuilding after a declared natural disaster. In FY 2023-24, NCEP will expand to include market-rate single and multifamily housing. Also, this year, to streamline the application process, 3CE is encouraging eligible applicants to submit funding requests post-project completion. The FY 2023-24 budget for the NCEP program is $1.1 million.
Qualified housing projects must be built to all-electric standards for energy needs including water heating, space heating, and cooking appliances. Incentives are based on the number of housing units and are provided upon successful project completion.
In the current fiscal year to date, 3CE has approved two applications for an all-electric ADU and an all-electric disaster rebuild, and distributed $307,500 for two completed affordable, multifamily developments in the City of Santa Cruz and Monterey County.
Electrify Your Home Program
On December 6, 2023, 3CE re-launched the Electrify Your Home (EYH) program, which continues to provide 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 to incentivize making the switch to all-electric heat pump technology. The FY 2023-24 budget for EYH is $1.5 million.
Contractors enrolled in TECH also have access to no-cost education and training on electrification design and specification, heat pump installation, building science, and sales and marketing for electric heat pumps. There are currently 75 licensed contractors enrolled in the TECH program that work in 3CE’s service area.
Electrify Your Ride Program
3CE’s Electrify Your Ride (EYR) program provides rebates for the purchase or lease of an electric vehicle (EV), for Level 2 EV Chargers, and electrical upgrades that may be needed to install chargers. The program also provides technical assistance for EV infrastructure buildout at publicly accessible commercial sites and at multifamily residential properties. The FY 2023-24 budget for EYR totals $4 million.
On January 5th, 3CE launched a Direct-Current Fast Charger (DCFC) program for eligible commercial, multifamily, and agricultural customers. Designed as a post-purchase rebate incentive, applicants can receive a rebate for 50% of the total purchase and installation costs of a DCFC, up to $100,000.00 USD.
Eligible projects must be publicly available; however, agricultural applicants may install DCFCs on a private lot to support electrification of agricultural equipment. Incentives are available on a first come, first served basis until funding has been fully awarded. Higher incentive amounts are given to income-qualified customers and multifamily-unit buildings to promote greater adoption of transportation electrification in disadvantaged and low-income communities.
In the current fiscal year to date, 3CE has received 649 applications and approved nearly $984,000 in incentives. The following figure shows applications by county:
FY 2023-24 EYR FUNDS DISTRIBUTED BY COUNTY
SUM OF REBATES = $984,000
Monterey County
San Benito
County
San Luis Obispo
County
Santa Barbara
County
Santa Cruz
County
Figure 1 (above): Electrify Your Ride funds distributed by County in FY 2023-24. 2%
30%
27%
20% 21%
FY 2023-24 EYR FUNDS DISTRIBUTED BY MEASURE
SUM OF REBATES = $984,000
Battery EV
EV
Readiness
Level 2 EV
Charger
Figure 2 (above): Shows Electrify Your Ride Program funds distributed by Measure type in FY 2023-24.
Income Qualified
- Tier 1
Income Qualified
- Tier 2
N/A
Figure 3 (above): Funds distributed to income-qualified applicants.
Tier 1 = 201 - 400% Federal Poverty Level (FPL); Tier 2 = <200% FPL; N/A = 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 funding for the purchase of an all-electric bus. In FY 2023-24, the budget for the Electric Bus program is $2 million.
Applications are accepted on a rolling basis 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 provide applicants with assurances 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 source restrictions apply.
8%
60%
31%
FY 2023-24 EYR FUNDS
% Income Qualified Incentives Distributed
63%
22%
15%
To date, 3CE has received one application for an electric school bus to serve a Title 1 school in Monterey County and two School District applications from Santa Cruz and Santa Barbara counties. Payments for an electric school bus charger in Los Olivos and an electric bus rebate in Orcutt have also been made.
Agricultural Electrification Program
3CE’s Agricultural (Ag) Electrification program provides rebates to ag 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 provides technical assistance for EV infrastructure buildout at agricultural customer sites. The FY 2023-24 budget for Ag Electrification is $1.8 million.
Rebates for equipment with higher estimated GHG emissions avoidance and those benefiting small to medium sized businesses are supported by greater incentive levels. 3CE covers up to 50% of the cost for farm equipment, providing up to $15,000 USD for smaller “Tier 1” equipment and up to $75,000 USD for larger “Tier 2” equipment. Program funds are offered as a post-purchase rebate.
Since the start of the current fiscal year, 3CE has received three Tier 1 applications and three Tier 2 applications for the Ag Electrification Program in Santa Barbara (2 applicants), Monterey (1 applicant), Santa Cruz (2 applicants), and San Benito (1 applicant) Counties.
FY 2023-24 3CE Member Agency Programs
This report provides an update on Central Coast Community Energy’s FY 2023-24 Member Agency programs.
Reach Code Program
3CE’s Reach Code program for Member Agencies provides no-cost technical assistance to help local cities and counties adopt and implement reach codes. Services include public and stakeholder presentations, ordinance creation, staff presentations and report review, and development of enforcement mechanisms. 3CE’s FY 2023-24 Reach Code program budget is $100,000.
To date in FY 2023-24, 3CE has engaged three Member Agencies:
Member Agency Reach Code Type
City of San Luis Obispo New Construction and Existing Buildings City of Santa Cruz Existing Buildings
City of Goleta Electric Vehicle Charging Infrastructure Electrify Your Fleet Program
3CE’s Electrify Your Ride (EYF) program provides rebates to Member Agencies for the purchase or lease of eligible vehicles. 3CE Member Agencies are eligible for up to $150,000 in EYF rebates each year.
Applicants are encouraged to apply to the program following the purchase/lease and delivery of eligible vehicles. Since launching the program on October 1, one application has been received.
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 CYF each year. 3CE’s 2023-24 CYF budget totals $1.2 million.
One application has been received this fiscal year to date for twenty Level 2 charging ports.
Plan Your Fleet Program
3CE’s Plan Your Fleet (PYF) program provides no-cost planning, design, and engineering consulting to Member Agencies to accelerate fleet electrification and EV charging infrastructure development across the Central Coast. 3CE’s FY 203-24 budget for PYF is $250,000.
This fiscal year to date, two Member Agencies have expressed interest in and are preparing to apply to the PYF program.
Member Agency Building and Transportation Electrification Working Groups 3CE is facilitating working groups made up of Member Agency staff focused on building and transportation electrification to promote existing programs and identify needs, barriers, and scalable solutions for regional electrification. The next working group event is currently scheduled for Spring 2024.
Staff Report Item 8
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Juan Lopez, Director of Finance
SUBJECT: Receive a Financial Report for the periods October 1, 2023 and December 31, 2023 DATE: February 21, 2024
RECOMMENDATION:
Receive a Financial Report for the period October 1, 2023, through December 31, 2023.
SUMMARY:
For the first quarter of FY 2023-24, operating revenues totaled $123.5 million, while operating expenses totaled $99.6 million for a net operating income of $23.9 million. Non-operating revenue added $3.0 million to total revenue, tallying a positive change in net position of $26.8 million.
The first quarter actuals versus budget are favorable. Operating revenue is lower than budget by $9.7 million, reflecting the seasonal nature of revenues and expenditures. Operating revenue should align with the budget as the fiscal year progresses. Investment revenue exceeds budget by $1.4 million due to staff active management in a favorable short-term interest rate environment. Non-energy operating costs were $4.8 million lower than budget as a result of vacancies and general operating cost reductions (due to timing). Energy costs were $3.3 million higher than budget.
Net position for the quarter grew by $26.8 million, an increase of 11.1%. Cash, cash equivalents, and short-term investments totaled $258.8 million, a 1.5% increase from the start of the fiscal year. Liquidity is expected to increase for the rest of the fiscal year as a result of the January and February 2024 rate changes in the PG&E and SCE territories. Modest increases in accrued revenue, collateral posted with the CAISO, and decreases in accrued electricity costs are factored into the increase in the net position. These positive results are expected to be minimized throughout the remainder of the fiscal year as energy costs and resource adequacy purchases materialize.
FISCAL IMPACT:
There is no financial impact associated with this report.
ATTACHMENT(S):
1. December 31, 2023 Financial Report
Compiled Financial Statements 1
Compiled Budgetary Comparison Schedule 6
Budget Variance Commentary 9
Financial Dashboard 10
Investment Summary 11
Accounts Receivable Aging Summary 12
Table of Contents
FINANCIAL REPORT
Fiscal Year to Date
As of December 31, 2023
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, 2023, and the related statement of revenues, expenses, and changes in net position, and the statement of cash flows for the period 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 29, 2024
1101 Fifth Avenue, Suite 200 San Rafael, CA 94901 415 459 1249 mahercpa.com
Current assets
Cash and cash equivalents - unrestricted 169,025,868 $
Accounts receivable, net of allowance 33,191,063
Accrued revenue 28,779,085
Other receivables 371,527
Loan receivable 188,951
Prepaid expenses 1,956,852
Deposits 16,054,329
Cash - restricted 294,000
Investments 89,742,481
Total current assets 339,604,156
Noncurrent assets
Deposits 23,182
Loan receivable 1,425,882
Lease asset, net of amortization 1,342,557
Capital assets, net of depreciation and amortization 549,748 Total noncurrent assets 3,341,369
Total assets 342,945,525
Current liabilities
Accrued cost of electricity 38,040,466
Accounts payable 1,763,185
Other accrued liabilities 955,105
User taxes and energy surcharges due to other governments 1,836,917 Lease liability 306,469
Security deposits - energy suppliers 501,000
Total current liabilities 43,403,142
Noncurrent liabilities
Security deposits - energy suppliers 29,756,280
Lease liability 1,089,039
Total noncurrent liabilities 30,845,319
Total liabilities 74,248,461
Net investment in capital assets 496,797
Restricted for security collateral 294,000
Unrestricted 267,906,267
Total net position 268,697,064 $
NET POSITION
As of December 31, 2023
STATEMENT OF NET POSITION
CENTRAL COAST COMMUNITY ENERGY
ASSETS
LIABILITIES
OPERATING REVENUES
Electricity sales, net 123,465,181 $
Total operating revenues 123,465,181
OPERATING EXPENSES
Cost of electricity 93,795,363
Contract services 2,308,380
Staff compensation 1,878,121
Other operating expenses 387,627
Program incentives 1,105,594
Depreciation and amortization 137,776
Total operating expenses 99,612,861
Operating income (loss) 23,852,320
NONOPERATING REVENUES (EXPENSES)
Interest and investment returns 2,993,099
Interest and financing costs (19,680)
Nonoperating revenues (expenses) 2,973,419
CHANGE IN NET POSITION 26,825,739
Net position at beginning of period 241,871,325
Net position at end of period 268,697,064 $
Three Months Ended December 31, 2023
AND CHANGES IN NET POSITION
STATEMENT OF REVENUES, EXPENSES
CENTRAL COAST COMMUNITY ENERGY
CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from customers 121,235,154 $
Receipts of deposits and collateral 25,330,483
Payments to suppliers for electricity (102,386,584)
Payments of deposits and collateral (34,890,718)
Payments for other goods and services (3,055,453)
Payments for program incentives (1,792,402)
Payments of staff compensation (1,617,687)
Payments of taxes and energy surcharges to other governments (2,029,548) Net cash provided by operating activities 793,245
CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES
Interest and related expense payments (3,440)
Net cash provided by non-capital financing activities (3,440)
CASH FLOWS FROM CAPITAL AND RELATED
FINANCING ACTIVITIES
Payments of lease liability (88,106)
Payments to acquire capital assets (42,028)
Net cash provided (used) by capital and related financing activities (130,134)
CASH FLOWS FROM INVESTING ACTIVITIES
Investment income received 2,457,308
Proceeds from investment sales 19,214,155
Principal payments received of loan receivable 93,165
Purchase of investments (49,138,300)
Net cash provided (used) by investing activities (27,373,672) Net change in cash and cash equivalents (26,714,001)
Cash and cash equivalents at beginning of year 196,033,869 Cash and cash equivalents at end of period $ 169,319,868 Reconciliation to the Statement of Net Position
Cash and cash equivalents - unrestricted $ 169,025,868
Cash - restricted 294,000
Cash and cash equivalents $ 169,319,868
Three Months Ended December 31, 2023
STATEMENT OF CASH FLOWS
CENTRAL COAST COMMUNITY ENERGY
Operating income (loss) 23,852,320 $
Adjustments to reconcile operating income (loss) to net cash provided by operating activities
Depreciation and amortization expense 137,776
(Increase) decrease in:
Accounts receivable, net of allowance (431,788)
Accrued revenue (3,913,978)
Other receivables 3,865,058
Prepaid expenses (1,576,641)
Deposits (9,560,235)
Increase (decrease) in:
Accrued cost of electricity (10,882,010)
Accounts payable (993,751)
Other accrued liabilities 213,304
User taxes and energy surcharges due to other governments 83,190 Net cash provided by operating activities 793,245 $
CENTRAL COAST COMMUNITY ENERGY
STATEMENT OF CASH FLOWS (continued)
Three Months Ended December 31, 2023
RECONCILIATION OF OPERATING INCOME (LOSS) TO NET
CASH PROVIDED BY OPERATING ACTIVITIES
6 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 and a supplemental budgetary comparison schedule for the period ended December 31, 2023, 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 29, 2024
1101 Fifth Avenue, Suite 200 San Rafael, CA 94901 415 459 1249 mahercpa.com
2023/24 YTD
Budget
2023/24 YTD
Actual
2023/24 YTD
Budget Variance
(Under) Over
2023/24 YTD
Actual / Budget %
2023/24 Annual
Budget
2023/24 Budget
Less Actual
2023/24 Budget
Remaining /
Budget %
REVENUES AND OTHER SOURCES
Electricity sales 135,042,000 $ 125,127,777 $ (9,914,223) $ 93% 563,933,447 $ 438,805,670 $ 78% Uncollectible accounts (1,875,000) (1,664,200) 210,800 89% (7,500,000) (5,835,800) 78% Electricity sales, net 133,167,000 123,463,577 (9,703,423) 93% 556,433,447 432,969,870 78% Investment and miscellaneous income 1,600,000 2,994,703 1,394,703 187% 6,400,000 3,405,297 53% Total revenues and other sources 134,767,000 126,458,280 (8,308,720) 94% 562,833,447 436,375,167 78% EXPENDITURES AND OTHER USESCurrent Expenditures
Cost of energy 93,869,112 90,515,000 3,354,112 104% 520,297,514 426,428,402 82% Salaries and benefits 2,384,000 1,878,121 (505,879) 79% 9,537,076 7,658,955 80% Services and supplies 8,250,000 3,957,175 (4,292,825) 48% 32,998,857 29,041,682 88% Total current expenditures 101,149,000 99,704,408 (1,444,592) 99% 562,833,447 463,129,039 82% Surplus (deficit) $ 33,618,000 $ 26,753,872 $ (6,864,128) $ (26,753,872) - $
CENTRAL COAST COMMUNITY ENERGY
SUPPLEMENTAL BUDGETARY COMPARISON SCHEDULE
Three Months Ended December 31, 2023
CCA Program Surplus/(Deficit)
per budgetary comparison schedule: 26,753,872 $
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 71,867 Change in Net Position 26,825,739 $
REVENUES, EXPENSES AND CHANGES IN NET POSITION
CENTRAL COAST COMMUNITY ENERGY
BUDGET RECONCILIATION TO STATEMENT OF
Three Months Ended December 31, 2023
Budget Item YTD Variance Comment
Electric Sales Revenue (7.3%) 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 3.7% 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 (21.2%) Staffing expenses are under budget due to the timing of new hires.
Professional Services (67.1%) This category includes accounting, IT, technical and other consultants.
Legal Costs (59.3%) This category includes outside legal costs for regulatory and energy procurement needs.
Marketing and customer enrollment (58.4%) Variance is mostly due to the lower than anticipated costs of recent customer enrollments.
Data Management Services (7.6%) These fees non-discretionary and are charged on a per customer basis.
Utility Service Fees (4.7%) These are PG&E and SCE fees charged on a per customer basis.
Other General & Administrative (49.0%) This category includes occupancy costs, industry membership dues, and other general and administrative costs.
Energy and Related Programs (67.4%) Programs expenses have generally been delayed until future periods Budget Commentary for significant items
CENTRAL COAST COMMUNITY ENERGY
October 1, 2023 through December 31, 2023
$13.2
$22.9
Act
Bud
$29.6
$42.7
$36.1
$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
$123.5
$133.2
$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) 416 393 410
Budget 420 402 416 419 383 432 396 419 426 442 456 435
0 50
100
150
200
250
300
350
400
450
500
CUSTOMERS
SALES VOLUME
410 GWh
STD MARGIN
$13.2M (31%)
Δ in NET ASSETS
$12.0M
REVENUE
$42.9M
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: December 2023
Margin %
CUSTOMERS
456,000
ACTIVE
December revenue of $42.9M accounts for
410 GWh in net retail consumption, 6 GWh
below budget.
YTD Electricity revenue is $123.5M
compared to budget of $133.2M. YTD
Direct Margin (defined as Electricity Sales
less Cost of Energy) of $29.6M is below
budget by $13.1M.
The chart to the right shows volume
comparison to budgeted volume.
The charts below display cumulative
revenue and margin $ vs budget.
41%
47%
12%
36%
48%
17%
Res
Com
Ag
YTD Month
45%
45%
11%
39%
46%
15%
Res
Com
Ag
YTD Month Revenue $42.9
C.O.E. $28.7
OpEx $2.3
Net Income $12.0
31.4%
51.2%
Act
Bud
Margin $
10
Return of Investments YTD Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep CASH AND CASH EQUIVALENTSRiver City Bank - Money Market and other Interest Earning AccountsFunds Invested - Average Balance $ 109,380,169 127,068,814 $ 100,067,132 $ Gains/Losses/Interest $ 1,051,592 $ 382,898 328,802.57 339,891.42 Average APY 3.62% 3.61% 4.08%INVESTMENTSRiver City Bank - Treasury-indexed productsFunds Invested - Average Balance $ 40,000,000 $ 50,000,000 $ 40,000,000Gains/Losses/Interest $ 627,907 178,385.54 213,485.85 236,035.13 Average APY 5.35% 5.12% 7.08%RBC GAM / Principal Financal/ Schwab/ ChaseFunds Invested - Average Balance $ 89,306,054 $ 94,745,123 $ 110,223,316 Gains/Losses/Interest $ 1,288,693 375,490.63 434,211.19 478,991.16 Average APY 5.05% 5.50% 5.21%
CENTRAL COAST COMMUNITY ENERGY
Investment Summary
October 1, 2023 through December 31, 2023
11
Current 0 - 30 Days 31 - 60 Days 61 - 90 Days > 91 Days A/R Balance $ 17,851,987 $ 11,784,440 $ 3,158,102 $ 724,961 $ (328,427) $ 33,191,063
CENTRAL COAST COMMUNITY ENERGY
Summary of Accounts Receivable, Net of Bad Debt Allowance As of December 31, 2023
12
Staff Report Item 9
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
SUBJECT: CEO Report
DATE: February 21, 2024
STAFFING UPDATE
On January 8, 2024, Geoff Ihle joined as the Energy Risk Manager. Geoff has previously helped build a deal capture system as part of other CCA risk management groups. Prior to that, he held positions at the Public Utility Commission of Oregon and at several Berkshire Hathaway Energy subsidiaries.
Kalia (“Kali”) Mitchell-Silbaugh joined Central Coast Community Energy as a Policy Advisor on January 16, 2024. Kali is from Davis, California, and graduated summa cum laude from the University of California, San Diego, where she studied literature/writing. She previously worked as the legal assistant to the outside regulatory counsel for several CCAs.
IMPLEMENTATION DATE FOR CITY OF ATASCADERO AND COUNTY OF SAN LUIS OBISPO CONFIRMED On December 18, 2023, 3CE received a letter from the California Public Utilities Commission confirming that 3CE had met its expansion requirements and setting January 1, 2025, as the “implementation date” to allow the residents and businesses within the City of Atascadero and the County of San Luis Obispo to begin receiving service as 3CE customers. In preparation for enrollment, 3CE will begin coordination with staff from both jurisdictions to develop comprehensive, locally relevant community engagement plans.
Initial kickoff meetings will be held February and early March 2024; the community engagement plans will be submitted to the 3CE Operations Board in May 2024 and the Policy Board in June 2024.
FRONT OF THE METER ENERGY STORAGE PROGRAM REDESIGN
Launched in late 2021, the Front of the Meter Energy Storage (FMES) initiative has a goal of installing up to 100 MW of small-scale energy storage devices, sized between 1 to 5 MW, throughout the 3CE service area to provide local grid resilience.
The effort has faced numerous challenges, including: an inefficient and cost-uncertain interconnection process, increased battery costs, inflationary pressure, and obtaining land control of suitable sites. The lack of viable project locations compounded the increasing cost pressures as 3CE could not leverage its the bulk purchasing power over several projects.
3CE remains committed to the FMES effort and will revisit the FMES effort to determine program improvements for project location identification, site control, and interconnection to ensure a successful future effort.
3CE REVIEW OF BEHIND-THE-METER ENERGY STORAGE FOCUSED DEMAND RESPONSE PROPOSALS On December 6, 3CE issued a request for proposals seeking vendors to design, manage, and implement a behind-the-meter battery energy storage program, with the goal of promoting customer load-shifting to further reduce reliance on fossil fuels and contribute to grid resiliency. The RFP requested proposals to support battery installation for both residential and non-residential customers, preserving the option to hire multiple vendors to run programs specific to various customer segments, if desired and based on the responses received. Four proposals were submitted by the January 26 due date. Staff have engaged the Community Advisory Council and sought input from local stakeholder groups to help tailor 3CE’s behind-the-meter battery energy storage program to meet the needs of our communities.
EXPANSION OF SYSTEM RELIABILITY PILOTS - AgFIT
On January 25, the California Public Utilities Commission (CPUC) issued a decision authorizing expansion of successful demand flexibility pilot programs to include Community Choice Aggregators (CCAs).
In 2022, CCA Valley Clean Energy (VCE) launched a pilot program with Pacific Gas & Electric (PG&E) which incentivized agricultural customers to shift irrigation operations to periods of the day when renewable energy is abundant by offering real-time variable rates-based market prices. The program met with support from agricultural customers who shifted irrigation hours without impacting operations and receive savings on their energy bills as a result. By 2023, VCE had enrolled 3.1 MW of load.
PG&E was directed to expand this program, called AgFIT, throughout its service territory by including other CCAs. The CPUC decision instructs PG&E to target a combined 100-megawatt-load-shift away from peak hours (50-megawatt enrollment per pilot) and authorizes the utility to spend up to $36 million on customer incentives, administration, and marketing. CCAs will receive an incentive of $20 per kilowatt for each year of customer enrollment in the program.
PROPERTY ACQUISITION
Staff successfully negotiated and closed on the purchase of 1026 Palm Street in downtown San Luis Obispo. Our next step is to solicit an architectural firm to design and remodel the space for 3CE’s needs.
Customer Enrollment and Engagement Report
Central Coast Community Energy
Communications and Outreach
January 2024
Member Agency Services
3CE sponsored the City of Solvang Tree Lighting Ceremony and Yuletide month, sponsoring the electricity to light the official tree for the month.
Staff attended the San Luis Obispo State of the State event featuring Senator John Laird and veteran Journalist David Lesher. This event provided insight on how policy and politics in Sacramento impact businesses on the Central Coast and was well attended by Member Agency staff and community organizations. 3CE Account Team sent Member Agency staff an email to keep staff apprised of updates concerning communications and outreach efforts, rate changes, Member Agency and community programs, as well as the San Luis West Solar plus Storage project and the SunZia Wind project. These email updates are sent mid-way between Member Agency Quarterly Meetings to ensure staff is kept apprised of updates and changes. 3CE Communications Team sent the monthly Content Share to Member Agency Communications staff to assist with timely content for social media and newsletters.
Enrollment Statistics
Monterey
33%
San Benito
5%
San Luis Obispo
14%
Santa Barbara
25%
Santa Cruz
23%
Percentage of Total Accounts by County
Enrollment as of January 1, 2024
Member Community % of Eligible Accounts % of Eligible Load ARROYO GRANDE 94.87% 93.02%
BUELLTON 96.89% 94.53%
CAPITOLA 95.19% 97.80%
CARMEL 97.63% 97.53%
CARPINTERIA 95.73% 98.70%
DEL REY OAKS 95.85% 96.89%
GOLETA 95.43% 87.90%
GONZALES 87.48% 97.08%
GREENFIELD 88.05% 94.93%
GROVER BEACH 96.42% 95.77%
GUADALUPE 97.55% 99.15%
HOLLISTER 89.07% 91.75%
MARINA 93.84% 92.20%
MONTEREY 95.85% 92.75%
MONTEREY COUNTY 92.88% 95.02%
MORRO BAY 96.96% 95.51%
PACIFIC GROVE 96.77% 96.67%
PASO ROBLES 92.10% 85.55%
PISMO BEACH 95.58% 95.97%
SALINAS 90.18% 93.42%
SAN BENITO COUNTY 90.93% 94.44%
SAN JUAN BAUTISTA 91.28% 91.79%
SAN LUIS OBISPO 96.03% 97.28%
SAND CITY 93.41% 67.36%
SANTA BARBARA COUNTY 94.82% 80.34%
SANTA CRUZ 96.32% 96.15%
SANTA CRUZ COUNTY 95.04% 94.78%
SANTA MARIA 97.91% 91.70%
SCOTTS VALLEY 96.52% 94.63%
SEASIDE 94.34% 96.14%
SOLEDAD 88.83% 94.09%
SOLVANG 96.82% 96.08%
WATSONVILLE 91.06% 94.00%
Media Outreach
December 2023
Facebook
Followers: 1.7K
Post Reach: 2.2K
Post engagement: 2.5K
New page followers: 3
Link Clicks: 84
Top Performing Content: City of Capitola’s electric
street sweeper
Facebook En Espanol
Followers: 165
Post Reach: 74
Post engagement: 74
New page followers: 0
Link Clicks: 3
Top Performing Content: Day of Service Beach
Cleanup
Instagram
Followers: 1.1K
New Followers: 16
Reach: 1.6K
Top Performing Content: City of Capitola’s electric
street sweeper
Twitter
Followers: 1.1K
Top Performing Content: 3CE’s All-Electric
Gingerbread House
LinkedIn
Followers: 2.2K
Top Performing Content: 3CE’s Day of Service Beach Cleanup Earned media:
Top SLO County stories in 2023: Bribery Arrest County upheaval 2023 was hard for many. But here are 10 good things that happened in SLO County | Opinion Solvang Julefest tree lighting ceremony sets tone
for weeks of holiday fun
Staff Report Item 10
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Dennis Dyc-O’Neal, Chief Operating Officer SUBJECT: Receive presentation on the challenges and impacts of the 2025 Compliance Year implementation of the 24-Hour Slice of Day Resource Adequacy Paradigm DATE: February 21, 2024
RECOMMENDATION:
This recommends the Policy Board receive a presentation on the challenges and impacts of the 2025 Compliance Year implementation of the 24-Hour Slice of Day Resource Adequacy Paradigm.
DISCUSSION:
In 2004, the California Public Utility Commission (CPUC) adopted a Resource Adequacy (RA) policy paradigm (Public Utilities Code section 380) to ensure the reliability of electric service in California. The RA policy paradigm acts as an “insurance program” to ensure adequate electric generation supplies are available through the state to meet customer demand. The RA program also promotes additional generation investment by requiring the procurement of “capacity” and not just “energy.” The CPUC established RA obligations applicable to all Load Serving Entities (LSEs) within the CPUC’s jurisdiction, including investor-owned utilities (IOUs), energy service providers (ESPs), and community choice aggregators (CCAs).
Non-compliance by LSEs to meet their RA obligations results in financial penalties and, more recently, non-financial penalties aimed at CCAs – such as limiting local government authority to pursue its rights under Public Utilities Code section 366.2 to join a CCA.
The accelerated buildout of intermittent renewable generation resources, the retirement of baseload and traditional combustion generation resources, and delays in interconnecting sufficient energy storage assets have made the grid more susceptible to “stress events” where consumption nears or
exceed available generation resources. For the past few years, California regulators have been working on a wholesale revamp of their existing RA paradigm known as a “Peak Load” method. In 2023, that effort resulted in a new RA paradigm called “24-hour Slice-of-Day” (SOD).
The new SOD paradigm requires procurement of capacity resources to satisfy each hour of the day during the highest consumption day of the month. The new SOD paradigm will further change counting rules for determining the qualifying capacity each resource technology (solar, wind, geothermal, combustion, energy storage) provides to the grid.
The CPUC has been working to establish rules, reporting structures, and otherwise implement this new paradigm to take effect in 2025.
3CE’ recently established RA strategy anticipated the 24-Hour SOD paradigm shift. That RA strategy provides for building additional capacity and hedging RA needs over longer terms.
Staff continues to work with the CPUC and other stakeholders to seek additional regulatory reforms that will meet the state’s climate policies with reliable clean power while also controlling costs.
ATTACHMENT(S):
None.
Staff Report Item 11
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Mary Federico, Billing Operations and Rates Analyst SUBJECT: Adopt Resolution No. PB-2024-02 establishing a 3CE Net Billing Tariff (NBT), with an implementation date of June 1, 2024.
DATE: February 21, 2024
RECOMMENDATION:
Adopt Resolution No. PB-2024-02 establishing the 3CE Net Billing Tariff (NBT), with an implementation date of June 1, 2024.
BACKGROUND:
NBT (previously referred to as NEM 3.0), the latest Net Energy Metering (NEM) tariff, became eligible statewide for all NEM applications received after April 15, 2023. While investor-owned utilities’ (IOUs) billing and system upgrades were developed, customers qualifying for NBT have been served on the legacy NEM 2.0 tariff until their IOU and 3CE NBT implementation date. Beginning December 2023 and extending into 2024, the IOUs have been working on transitioning qualifying customers away from the NEM 2.0 tariff and onto NBT.
SCE has delayed its start date and asked the Energy Division (ED) for an extension to Dec 21, 2023, a week later than originally planned. On Dec 14, 2023, PG&E was granted an extension to implement residential NBT on Apr 15, 2024, four months later than originally planned. PG&E plans to implement non-residential NBT in June 2024.
DISCUSSION/ANALYSIS:
3CE staff approached building the proposed 3CE NBT by examining the aspects of the IOU NBT that are unique from the previous NEM 1.0 and 2.0 tariffs and determining what aspects best serve 3CE and its customers. The following characteristics were evaluated when designing the proposed NBT.
Monthly Billing
o All 3CE customers enrolled in the NEM program are currently being billed monthly. Having NBT enrolled customers also billed monthly is consistent with the current NEM process. Energy Export Credit
o 3CE examined at what interval the export compensation should be calculated. The IOUs will send the NBT data in hourly format. This approach aligns with 3CE costs, which are assessed at an hourly level by the CAISO. Staff proposes using an hourly Energy Export Credit (EEC) as the most straightforward methodology.
o Staff proposes that the IOU EEC hourly generation rates be used from the start of 3CE NBT service through December 2024. The intervening time will be used to evaluate the effectiveness of mirroring the IOU rates and determine if 3CE should develop a distinct set of rates for 2025 and beyond.
Energy Export Credit Adders
o 3CE considered the need for a flat $/kWh adder to the EEC to minimize the bill impacts for CARE and FERA customers with a newly installed NEM paradigm. 3CE proposes implementing an income qualified EEC adder for a period of nine years after their NBT start date.
o The Low-Income EEC Adder was calculated as 10% of the average EEC from 2023-2027 weighted by the current 3CE NEM exported generation in kWh. True-Up Methodology
o The NBT methodology is structured differently from the current 3CE NEM process. 3CE proposes that the 3CE NBT true-up methodology mirrors the IOU process. This process is designed such that the customer’s remaining banked credits from netted usage is considered on an annual basis and that excess generation is compensated for exclusively by the NSC rate in place of retail.
Implementation
NBT implementation will be done in partnership with Calpine, 3CE’s back-office provider. Beginning in the summer of 2023, Calpine began planning the development work needed to implement NBT billing for its CCA customers. A standard offering was developed that Calpine would have ready for implementation at the same time as the IOUs planned NBT start dates. That fall, work had begun to upgrade their billing systems for the standard offerings. As of December 2023, Calpine began successfully billing NBT customers in SDG&E and SCE territories.
3CE’s proposed NBT is in line with the standard offering being developed by Calpine with one notable exception. The proposed 3CE Low Income Adder is designed to be excluded from the balance reset during the annual true-up. Implementing this characteristic of the adder will require extra development time and will be available before the annual true-up in December 2024.
Proposed Enrollment Timeline
3CE staff proposes implementing NBT for all residential and non-residential qualifying customers in SCE and PG&E territories in June 2024. This positions 3CE and our customers to transition to NBT at a time when the IOUs have stabilized their own implementations, and our back-office provider has gained experience in implementing NBT billing in both IOU territories. Should the PG&E non-residential implementation date be delayed, 3CE may need to delay implementation in kind to align all customers to the same implementation timeline.
Bill Impacts and Estimated Cost to 3CE
3CE engaged NewGen to analyze the average bill impacts residential customers can expect when transitioning from NEM 1.0 or NEM 2.0 to NBT. An average 3CE residential NEM hourly profile was identified to calculate the bill impact. The average 3CE residential NEM customer is a net consumer of 127 kWh monthly, and 1,528 kWh annually. Using the average 3CE residential NEM hourly profile, it is estimated that 3CE residential NBT customers will have an average generation charge of $36.33 per month (see Table 2 in attached NewGen NBT Memo). This is an increase of $18.67 per month when compared to NEM 1.0 or 2.0 estimated monthly generation charges. This increase in average monthly charges demonstrates a reduction in subsidization achieved by aligning the NBT generation credit with the hourly avoided costs and compensating customers using a value that captures the value of the exported energy to 3CE. The reduction in subsidy will encourage home battery installations to maximize solar installation value. 3CE is in development of a battery storage incentive and load shifting program to maximize benefits to the grid and NBT customers and programs staff will be bringing that forward at a future date for board consideration.
Community Input
To collect input on 3CE’s proposed NBT structure and battery storage incentive / load shifting proposal, 3CE staff met with five advocacy groups (four local, and one statewide), nine local solar installers, several current/past customers who have historically provided input on 3CE’s NEM program, and four community-based organizations (CBOs).
More than 13% of 3CE’s NEM enrolled customer accounts participate in the bill payment assistance programs CARE and FERA. Therefore, staff met with CBOs that provide payment assistance services to income-qualified community members. While these CBO stakeholders did not have specific input on the NBT or program concepts, they shared feedback on how our agency could better serve these customers.
Including an EEC adder for low-income customers.
Across the board, non-CBO stakeholders responded positively to 3CE’s goals of incentivizing battery storage and providing equitable rates to all customers. Input that was consistent across each stakeholder
group included support for a Low-Income EEC adder based on CARE/FERA status and a general desire for a “glide path” to ease the transition from the legacy NEM 2.0 tariff. All stakeholder groups also supported a battery storage incentive program, even where the incentive would provide 3CE partial dispatch control. 3CE staff considered the input received from stakeholders regarding the fair rate design, the ability to use credit balances for the full relevant period, and the Low-Income EEC adder. These inputs have been incorporated into the recommended NBT rate design. The feedback received for a battery storage incentive program will be considered for future related program design recommendations.
FISCAL IMPACT:
The fiscal impact will vary from customer-to-customer dependent on their generation exported to the grid and the proposed low-income EEC adder will increase the total cost to 3CE and its non-NEM enrolled customers. It is anticipated that in the in the initial years following implementation the fiscal impact will be minimal due to the expected small number of qualified NBT customers during that period.
CONCLUSION:
The Board’s approval of the 3CE NBT will further 3CE’s effort to encourage battery storage adoption and enable demand response, load shifting, and peak shaving opportunities. Staff is continuing its exploration of a robust batter storage incentive program it is expected to assist in grid reliability by laying the groundwork for demand response capabilities.
ATTACHMENTS:
1. Draft Resolution No. PB-2024-02 Net Billing Tariff
2. NewGen NBT Memo
DRAFT RESOLUTION NO. PB-2024-02
A RESOLUTION OF THE CENTRAL COAST COMMUNITY ENERGY POLICY BOARD OF DIRECTORS ADOPTING ESTABLISHING THE 3CE NET BILLING TARIFF, WITH AN IMPLEMENTATION DATE OF JUNE 1, 2024.
WHEREAS, Central Coast Community Energy (“CCCE”) 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 Counties, and certain cities within San Luis Obispo County; and
WHEREAS, CCCE 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, on December 15, 2022, the California Public Utilities Commission issued a decision reducing overall compensation for rooftop solar for new solar customers, increased the economic payback for battery storage, and provided added compensation for low-income customers (“NEM
3.0 Decision”); and
WHEREAS, 3CE staff approached building the proposed 3CE Net Billing Tariff (NBT) by examining the aspects of the IOU NBT that are unique from the previous NEM 1.0 and 2.0 tariffs and determining what aspects best serve 3CE and its customers; and
WHEREAS, 3CE staff proposes implementing NBT for all residential and non-residential qualifying customers in SCE and PG&E territories in June 2024, positioning 3CE and its customers to transition to NBT at a time when the IOUs have stabilized their implementations, and our back-office provider has gained experience in implementing NBT billing in both IOU territories, and may need to delay implementation in kind to align all customers to the same implementation timeline should the PG&E non-residential implementation date be delayed.
WHEREAS, 3CE met with advocacy groups, solar installers, past and current customers, and community-based organizations (CBOs) to collect input on 3CE’s NBT proposal and possible battery storage incentive program (BSIP). Across the board, non-CBO stakeholders responded positively to 3CE’s goals of incentivizing battery storage, continuing to build a clean and renewable grid, and providing equitable rates to all customers. Input that was consistent across each stakeholder group included the strong and unanimous desire for an NBT where generation credits cover generation charges from the entire true-up period, near unanimous support for a low-income adder to the EEC based on CARE/FERA status, and support for a BSIP program with a grid-control element.
NOW, THEREFORE, THE CENTRAL COAST COMMUNITY ENERGY POLICY BOARD OF DIRECTORS DOES HEREBY RESOLVE, DETERMINE, AND ORDER AS FOLLOWS:
1. The Policy Board hereby adopts:
a. CCCE’s Net Billing Tariff attached hereto as Attachment A, with an implementation date of June 1, 2024.
PASSED AND ADOPTED this 21st Day of February 2024, by the following vote:
AYES:
NOES:
ABSENT:
__________________________________
Chair, Das Williams
__________________________________
Board Clerk, Heather Vowell
ATTACHMENT A
Net Billing Tariff (NBT)
APPLICABILITY:
The Net Billing Tariff (NBT) Schedule, also known as Solar Billing Plan (SBP), is applicable to the generation portion of the customer’s electric utility bill for Central Coast Community Energy (3CE) customers who meet the following criteria:
The customer is operating a Renewable Electrical Generating Facility (REGF) as defined by PG&E and SCE’s Net Billing Tariff. 1
Submitted an interconnection application to PG&E or SCE on April 15, 2023, or later; or
Legacy Net Energy Metering (NEM) 1.0 or NEM 2.0 customers whose Legacy Period has ended.
Beginning April 15, 2023, customers meeting the above criteria will be interconnected under NBT but temporarily billed for generation under NEM 1.0 and NEM 2.0 until the scheduled 3CE transition date.
3CE customers may voluntarily elect to transition to the 3CE NBT from NEM 1.0 or NEM 2.0 ahead of the end of their Legacy Period. Once transitioned, either voluntarily or at the end of their Legacy Period, the customer may not return to NEM 1.0 or NEM
2.0 service.
RATES:
Customers’ import charges for electricity consumed on site will be charged by applying the 3CE rates adopted by the 3CE Policy Board2 according to their Otherwise Applicable Tariff (OAT) or Otherwise Applicable Metered Rate Schedule (OAS), the eligible Time-of-Use (TOU) rate code provided to 3CE by the incumbent Investor-Owned Utilities (IOUs).
1 SCE Net Billing Tariff and PG&E Net Billing Tariff (NBT) Service available at:
https://www.sce.com/regulatory/tariff-books/rates-pricing-choices/other-rates and https://www.pge.com/tariffs/index.page.
2 See current 3CE rates at: https://3cenergy.org/billing/
All NBT customers’ export credits for electricity exported to the grid will be credited by applying the Energy Export Credit (EEC) hourly rates3 adopted by the 3CE Policy Board.4
BILLING:
A. Import Charges
Monthly generation-related import charges will be calculated by multiplying the total electricity consumption for the TOU and billing period, measured by the import channel in kWh, by the applicable generation rate ($/kWh) as determined by the OAT or OAS.
B. Export Credits
Monthly generation-related export credits will be calculated by multiplying the hourly interval generation exported to the grid for the billing period, measured by the export channel in kWh, by the corresponding hourly interval EEC rates. The EEC rates are adopted by the 3CE Policy Board and based on the Avoided Cost Calculator (ACC)5 adopted by the California Public Utilities Commission (CPUC) and effective January 1 of each year.
Monthly generation-related export credits, post calculation, will offset any generation-related 3CE import charges in the same bill period or generation-related 3CE import charges within the same Relevant Period as defined below in Special Conditions Section (A). Generation-related 3CE export credits may not offset applicable taxes or IOU Transmission and Distribution (T&D) charges.
C.Low Income EEC Adder
3CE NBT customers with permission to operate NBT start dates from the 3CE NBT implementation start date to December 31, 2027 and enrolled in the California Alternate Rates for Energy (CARE) program and/or Family Electric Rate Assistance (FERA) program will receive a flat $/kWh adder6to their EEC for a period of nine (9) years from their NBT start date. The 3CE Low Income EEC Adder will present as a separate line item on the customers’ bill. Any banked Low Income EEC Adder amounts will not be subject to the balance reset during the Annual True-Up Process and will roll over to the next Relevant Period.
D. Monthly Billing
Aggregated 3CE import consumption charges and export generation credits will appear on the monthly statement received from the IOU. When the total 3CE import charges exceed the total 3CE export credits, the monthly statement will reflect a
3 Current 3CE EEC is available at: https://3cenergy.org/billing/solarbillingplan 4 Board agendas may be found at: https://3cenergy.org/meetings-agendas/. 5 Avoided Cost Calculator may be found at: https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/energy-efficiency/idsm. 6 More information on the 3CE Low Income EEC adder is at: https://3cenergy.org/billing/solarbillingplan
charge to the customer. Conversely, when the total 3CE export credits exceed the 3CE import charges, the excess credits will be banked, and the customer will receive a monthly statement with no energy charges for that month. Banked credit amounts will apply to future monthly charges and may be seen on subsequent monthly statements until fully used to offset 3CE charges or a true-up occurs.
E. Annual True-Up Process
At the end of the Relevant Period, the following steps will be performed by 3CE for NBT accounts:
1. Meter readings from the import and export channels during the Relevant Period are aggregated. If the export generation total exceeds the import consumption total, the aggregated total is multiplied by the Average Retail Export Compensation Rate ($/kWh).7 The resulting product is the Energy Export Credit Adjustment. If the import total equals or exceeds the export total, then the Energy Export Credit Adjustment is $0.
2. If there are remaining banked EEC amounts, these are first used to offset any applicable Energy Export Credit Adjustment. Next, all 3CE energy charges are summed and aggregated with all used EEC amounts. If the result is positive, any remaining banked EEC amounts offset the amount. The balance is reset to zero if any banked EEC amounts remain after the above process. Low Income EEC Adder amounts are not subject to the balance reset and will roll over to the next Relevant Period until used for 3CE charges or paid out when the account is returned to bundled service or terminated.
3. Net Surplus Compensation (NSC) is then calculated if the aggregated total of the import and export meter channels for the Relevant Period results in excess generation. NSC is calculated by multiplying the aggregated total by the 3CE NSC rate.8 Should any Energy Export Credit Adjustment amounts remain at the end of the process described in Section E.2 above, it will be netted with the NSC. If the resulting NSC amount exceeds the applicable thresholds (residential=$200; non-residential=$500), the amount is delivered on the true-up statement as a bill credit. If the NSC amount is less than the applicable thresholds, then the amount is carried over to the next Relevant Period. NSC amounts are never reset and may be seen on subsequent monthly statements until used for 3CE charges or the combination of multiple NSC amounts exceeds the threshold on a subsequent true-up. NSC amounts above the threshold may be requested to be delivered by check within 45 days of the true-up statement appearing on the bill.
SPECIAL CONDITIONS:
7 The 3CE Average Retail Export Compensation Rate can be found at:
https://3cenergy.org/billing/solarbillingplan
8 Current 3CE NSC rates can be found at: https://3cenergy.org/billing/nem/
A. Relevant Period
3CE defines the Relevant Period as all billing periods occurring in the 12 months, from the start of the customer's January meter read to the end of the December meter read.
B. Legacy Period
Legacy Period is defined as the time period that a NEM 1.0 or NEM 2.0 customer is grandfathered into their current NEM program. This period is defined as twenty (20) years from the original PTO date of the RGEF. Legacy Periods are tracked and communicated to 3CE by the customer’s incumbent IOU.
C.Return to Bundled Service
3CE NBT customers may voluntarily opt out of 3CE service at any time. A true-up of the current Relevant Period will occur on their last monthly statement with 3CE. The true-up will be processed according to the process detailed in Billing Section (E), with the noted exception that NSC thresholds do not apply to customers returning to bundled service.
D.Account Termination
3CE NBT customers that terminate their NBT account with the IOU are trued-up for the current Relevant Period on their last monthly statement. The true-up will be processed according to the process detailed in Billing Section (E), with the noted exception that NSC thresholds do not apply to customers terminating service.
E. Reservation of Rights
3CE reserves the right to modify or terminate components of the Net Billing Tariff at a duly noticed public meeting of the 3CE Policy Board. By enrolling or remaining enrolled in the NBT Tariff, the customer acknowledges and accepts 3CE’s reservation of rights.
F. Limitation of Liability
For any act or omission in the performance of this tariff, the sole and exclusive remedy shall be the amount of direct damage actually incurred. In no event shall any party subject to this tariff be liable for any indirect, special, consequential, punitive, or exemplary damages, including lost profits, business interruption damages, or attorney’s fees, whether in contract, tort, or strict liability.
Memorandum
Economics | Strategy | Stakeholders | Sustainability
www.newgenstrategies.net
225 Union Boulevard
Suite 450
Lakewood, CO 80228
Phone: (720) 633-9514
To: Mary Federico
From: NewGen Strategies and Solutions, LLC
Date: February 7, 2024
Re: Evaluation of Net Energy Metering Customer Transitions to Net Billing Tariffs – DRAFT Background
In November 2023, Central Coast Community Energy (3CE) engaged NewGen Strategies and Solutions, LLC (NewGen) to conduct a cost of service (COS) study and provide rate design, general rate, and regulatory support. Included in that support was further analysis of net energy metering (NEM) residential customers at 3CE and the impacts of implementing a Net Billing Tariff (NBT). This memo describes NewGen’s evaluation and estimation of the billing impacts of shifting from NEM to NBT for a representative NEM customer.
Central Coast Community Energy Net Energy Metering Customers As of the date of this memo, 3CE staff estimates indicate that there are between 175 megawatts (MW) and 260 MW of solar installed on the 3CE system (including all territories in 3CE’s service area as of February 2021) and 54,052 total NEM customers. In collaborating with 3CE staff, it was determined that an average 3CE NEM customer is a net consumer of 127 kilowatt hours (kWh) on a monthly basis (1,528 kWh annually). Of the total NEM customers on 3CE’s system, approximately 30% of current NEM residential customers act as net generators of electricity, meaning that at the end of a 12-month period, the customer generated more electricity from their rooftop solar than they consumed and thus exported that net generation to the grid. The remaining 70% of NEM residential customers function as net consumers of electricity.
To evaluate the transition for an average 3CE NEM customer to the NBT and related bill impacts, NewGen developed and used the following methodology and analysis:
Identified and calculated an average rooftop solar generation 8,760 hour profile that aligned with the average 3CE NEM customer that is a net 127 kWh consumer per month (this resulted in a proxy of a 2.85 kW rooftop solar capacity per NEM customer).
Applied the average solar generation profile to the average residential customer consumption to create the “average 3CE NEM customer’s” load profile.
Calculated the bill for the “average NEM customer” under 3CE’s current NEM rate and policy to the proposed NBT structure.
Memorandum
Mary Federico
February 7, 2024
230518490,,,NewGen NBT Memo
NewGen relied on the National Renewable Energy Laboratory’s (NREL) PV Watts online tool to generate rooftop solar generation hourly load profiles.
Current NEM Rate and Billing
The “average 3CE NEM customer” used in this analysis has an average monthly energy consumption of 515 kWh and average monthly generation of 388 kWh, resulting in an average net consumption of 127 kWh per month. The “average 3CE NEM customer” is also assumed to be on the E-TOU-C energy rate for NEM billing purposes as 30,000 of the approximately 46,000 total residential NEM customers utilize this rate. As shown in Table 1 under current NEM policies, the “average 3CE NEM customer” pays for net energy consumption, or in this case $17.67 per month on average.
Table 1
Average 3CE Residential
NEM Customer Monthly Bill
Item Cost or Rate
Customer Charge ($/month) $0.00
Energy Charge ($/kWh)
1 Summer Peak $0.2230
Summer Off-peak $0.0920
Winter Peak $0.1830
Winter Off-peak $0.0990
Billable Monthly Usage (kWh)
Summer Peak 1.40
Summer Off-peak (14.17)
Winter Peak 56.96
Winter Off-peak 83.17
Total Rate Charges ($/month)2 $17.67
1. E-TOU-C Rate as of 1/1/2024.
2. The monthly bill totals $17.67, reflecting the consumption profile of the “Average 3CE NEM customer” with usage of 127 kWh/month. Notably, there are higher consumption levels during Peak hours and lower consumption levels during Off-peak hours.
As is seen in Table 1, applying the E-TOU-C rate to a residential NEM customer results in a net cost or bill based on net consumption of energy (kWh) during the Summer Peak, Winter Peak, and Winter Off-Peak periods. An average 3CE NEM customer is generating energy (kWh) during the Summer Off-peak periods. The result of the NEM customer production and consumption of energy under the NEM billing structure results in an average monthly bill of $17.67. The relationship and illustration of how solar energy generation and an average 3CE NEM customer’s energy consumption profile is shown in Figure 1.
Memorandum
Mary Federico
February 7, 2024
230518490,,,NewGen NBT Memo
Figure 1
Figure 2 illustrates the relationship of solar energy generation from residential rooftops with CAISO hourly market prices for energy. This relationship and peaking solar generation during lower energy price periods in the CAISO is a key driver for the implementation of NBT to better align the value of solar production with/without storage, utility costs, market prices, and cost recovery for utilities.
Memorandum
Mary Federico
February 7, 2024
230518490,,,NewGen NBT Memo
Figure 2
Net Billing Option and Comparison to NEM Bill
Under current billing conditions, NEM customers earn full retail credit for the energy they generate. This means that a NEM customer who generates more energy than they consume in a month receive the applicable full retail pricing credit for the excess energy delivered to the grid. NEM customers can bank these energy credits when they generate more energy than they consume in a given month. By banking the energy credits the customer then applies them to offset future months’ costs and bills. If at the end of the 12-month period the customer has unused credits or dollars, that excess energy related to the credit is paid out at the Net Surplus Compensation rate (NSC) rather than the full retail credit.
NBT differs from NEM by applying the applicable retail rate to the hourly net consumption and a separate energy export rate to the hourly interval generation to the grid for a customer with distributed energy or rooftop solar. The key difference between NEM and NBT is the application of the export rate to excess generation rather than the retail consumption rate. 3CE is proposing that the incumbant IOU Energy Export Credit (EEC) will be the hourly value and price placed on the hourly excess generation from customers with distributed generation or rooftop solar. The retail prices charged for net hourly consumption will remain the applicable retail rate such as the residential E-TOU-C rate with on and off-peak period pricing.
Table 2 illustrates the impact of NBT for an average 3CE NEM customer.
Table 2
Monthly Bill for Average 3CE Residential
NEM Customer with the Net Billing Tariff
Item Cost or Rate
Customer Charge ($/month) $0.00
Energy Charge ($/kWh)
1 Summer Peak $0.2230
Summer Off-peak $0.0920
Winter Peak $0.1830
Winter Off-peak $0.0990
Billable Monthly Usage (kWh)
Summer Peak 18
Summer Off-peak 87
Winter Peak 71
Winter Off-peak 221
Monthly Average Excess Generation (kWh) 270
Total Consumption Charges ($/month)2 $47.01
Memorandum
Mary Federico
February 7, 2024
230518490,,,NewGen NBT Memo
Total Excess Energy Credit for Generation3($10.68)
Net Bill Total4 $36.33
1. E-TOU-C Rate as of 1/1/2024.
2. Total consumption equals the E-TOU-C rate times net consumption in the Peak / Off-peak periods.
3. Total Excess Energy Credit equals the hourly EEC rates times the net excess generation to the grid.
The EEC includes hourly rates for the 8,760 hours in the year.
4. The monthly bill totals $36.33, reflecting the total consumption charges less excess energy credits.
Applying the NEM rate to an average 3CE residential NEM customer results in an average monthly bill of $17.67 as seen in Table 1. However, the NBT results in an average monthly bill of $36.33 as seen in Table 2, which is an increase of $18.67 per month for distributed energy customers. The NBT will increase bills for residential distributed energy customers; however, it acts to reduce and eliminate the subsidy currently present and related to NEM billing and rate applications. By applying an hourly avoided cost or excess energy credit value to distributed energy customers, it more accurately reflects and aligns with the costs and benefits of a distributed energy customer on the utility system.
Staff Report Item 12
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Mary Federico, Billing Operations and Rates Analyst SUBJECT: Receive a Report on Efforts for Setting Rates Beginning FY 2024-25 DATE: February 21, 2024
RECOMMENDATION:
Receive a report on the efforts for setting rates beginning FY 2024-25.
BACKGROUND:
On August 21, 2023, 3CE issued a Request for Proposal (RFP) to contract a rate design consultant to complete a territory-wide rate study for the 3CE rate design process for calendar years (CYs) 2025 through 2027 and provide operational and rate support. In November 2023, the contract was executed with NewGen Strategies and Solutions, LLC.
DISCUSSION/ANALYSIS:
There are five larger steps involved in the rate-setting process. These steps include developing a revenue requirement, functionalizing costs, classifying costs, allocating costs, and rate design. 3CE is working with NewGen to complete a draft COS study that incorporates the first four of the five steps. The results of the study will provide information important to the analyses that will flow through to the rate design and inform the recommendation to be brought to the Policy Board at the June 2024 meeting.
Revenue Requirement
The revenue requirement is established by forecasting all expenses and costs incurred in the service of 3CE customers. A forecasted test year is established from the 2024 Fiscal Year (FY) Approved Budget and the 3CE forecasted load. The test year incorporates known and measurable adjustments to the base year to approximate the financial and operational conditions expected in CYs 2025 through 2027. Moving forward, 3CE will evaluate the selection of the test year as either an average of the three years or a single year and bring a recommendation to the Board at the June 2024 meeting.
Functionalized and Classified Costs
The test year is then functionalized and classified. As a CCA, 3CE does not have transmission or distribution categorized costs, so costs are functionalized into production, associated with the cost of energy (COE), or customer costs, associated with all other non-COE costs.
Next, the functionalized costs are classified as fixed or variable. Fixed costs do not vary from customer to customer and are made up of customer costs and the portion of COE related to demand. For CCAs, the demand portion of COE comprises of Resource Adequacy (RA) costs. Variable costs are associated with COE costs related to the hourly purchase of energy and will vary from customer to customer depending on their usage patterns. After functionalizing and classifying the draft test year, it was preliminary found that 37% of 3CE’s costs are related to fixed costs, and 63% of 3CE’s costs are related to variable costs.
Allocating Costs
The functionalized and classified costs are then allocated to various customer classes based on their share of the fixed costs and their annual load profiles. Nine distinct customer classes have been identified, grouped by their load profiles. These include Residential, Small Commercial, Medium Commercial, Large Commercial, Small and Medium Agricultural, Large Agricultural, Business Electric Vehicle, Standby, and Street Lights. 3CE will continue to examine the load profiles throughout the entirety of the service territory to determine a recommendation for any appropriate updates to the current rate classes.
Next Steps
The final step in the 3CE rate-setting process is rate design. 3CE expects to bring recommendations related to the following items to the June 2024 Policy Board Meeting:
Use of a single or averaged test year;
Definition of distinct customer classes;
Proposed future rate changes to meet the revenue requirements.
CONCLUSION:
The 3CE rate design process uses the COS methodology to inform the building of rate values that will recover the necessary revenue requirements from each customer class. Designing rates with this methodology will maintain 3CE’s strong financial position while providing competitive and fairly allocated rates to its customers. This report was presented to the Audit & Finance Committee on February 21, 2024.
FISCAL IMPACT:
Receiving this report does not have any fiscal impact.
ATTACHMENT(S):
None.
Staff Report Item 13
TO: 3CE Policy Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Juan Lopez, Director of Finance
SUBJECT: Receive a Presentation 3CE’s FY 2022-23 Audited Financial Statements DATE: February 21, 2024
RECOMMENDATION:
Receive a presentation on 3CE’s FY 2022-23 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. The Finance Department worked diligently with its accounting vendor and the external auditors, Pisenti & Brinker, over the past few months to ensure a proper review of 3CE’s financial controls and financial statements. The FY 2022-23 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 includes its opinion that 3CE’s FY 2022-23 Financial Statements present fairly, in all material respects, the financial position of 3CE as of September 30, 2023 and 2022, and the respective changes in financial position and cash. The Auditors’ Report contains what is generally regarded as an unqualified or “clean” audit opinion.
The auditor’s audit results letter states that they did not identify any internal control deficiencies that they consider a material weakness. Representatives from Pisenti & Brinker will be in attendance and available to answer questions during the Policy Board meeting.
FY 2022-23 Financial Highlights
The net position increased by $34.7 million, up from a $17.3 million increase in the prior year.
Cash, cash equivalents, and short-term investments grew by $71.5 million. Operating revenues grew over $49.9 million, driven primarily by the rate adjustments to reflect the increased cost of energy.
The cost of energy increased by approximately $32.1 million due to rising energy and resource adequacy costs and delays in new power projects resulting from interconnection delays, supply chain, and inflationary pressures.
Operating expenses, excluding the cost of energy, increased year over year from $21.7 million in FY 2021-22 to $27.8 million in FY 2022-23, an increase of 28.3%. Higher interest income from the increase in market interest rates stemming from rate hikes made by the Federal Reserve, resulting in $7.1 million in higher investment revenue than the prior year. Cash was positively impacted by the increase in net position, higher accrued electricity costs, and lower energy market settlements and accounts receivable. Cash was negatively impacted by higher accrued revenue. Higher accrued revenue arose primarily from an increase in retail electricity rates. Higher accrued electricity costs resulted from higher electricity costs and delays in supplier invoicing for renewable energy. Security deposits from energy supplies increased as a result of delays with PPAs.
The receipt and application of $1.5 million of California Arrearage Payment Program (CAPP) funds reduced eligible past-due accounts receivable.
FY 2022-23 Actuals Versus Budget
On May 10, 2023, the Operations Board received an update on the mid-year FY 2022-23 budget forecast.
The mid-year budget amendment sought to align expenditures and revenues resulting from external and internal factors, including higher energy costs and changes to electric generation rates.
Year-end actuals versus budget are favorable and speak to the value of the mid-year budget amendment.
Operating revenue was under budget by $3.4 million, a 0.8% variance. Investment revenue was $2.2 million over budget, thanks to higher-than-expected interest rates. The total revenue was $0.5 million under budget, a negligible variance supported by higher-than-estimated investment revenue. Operating expenditures were $17.7 million under budget, a 4.5% variance. Energy costs were $4.5 million under budget, a 1.1% variance. Non-energy operating costs were 33.1% under budget due to lower energy program current year expenditures, personnel, and administrative costs. Net income was $17.2 million over budget.
CONCLUSION:
For the year ending September 30, 2023, 3CE increased its net position and liquidity by $34.7 million and $71.5 million, respectively. These results and ongoing efforts by staff are strong indicators of 3CE’s sound financial health and positioned to serve its customers and deliver on its mission. A strong net position of $243.3 million supports 3CE’s newly adopted Financial Policies that established robust strategic reserves to sustain service delivery. Adequate reserves enable flexible financial planning to develop rate structures and future capital projects and deal with unforeseen emergencies. This report was presented to the Audit & Finance Committee on February 21, 2024.
FISCAL IMPACT:
There is no financial impact by receiving this report.
ATTACHMENTS:
1. FY 2022-23 Audited Financial Statements
2. FY 2022-23 Supplemental Budgetary Schedule, Investment Summary, and Dashboard
Financial
Statements
Years Ended September 30, 2023 and 2022
INCLUDING REPORT OF INDEPENDENT AUDITORS
CENTRAL COAST COMMUNITY ENERGY
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
TABLE OF CONTENTS
Independent Auditor’s Report ………………………………………………………................ 1 Management’s Discussion and Analysis ……………………………………………................ 3 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
SANTA ROSA PETALUMA
RSM US Alliance member firms are separate and independent businesses and legal entities that are responsible for their own acts and omissions, and each are separate and independent from RSM US LLP. RSM US LLP is the U.S. member firm of RSM International, a global network of independent audit, tax, and consulting firms. Members of RSM US Alliance have access to RSM International resources through RSM US LLP but are not member firms of RSM International. 3562 Round Barn Circle, Suite 200
Santa Rosa, CA 95403
(707) 542-3343 Office
(707) 527-5608 Fax
pbllp.com
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), as of and for the years ended September 30, 2023 and 2022, and the related notes to the financial statements, which collectively comprise 3CE’s basic financial statements as listed in the table of contents.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of 3CE as of September 30, 2023 and 2022, and the changes in financial position 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 Audits 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.
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.
Independent Auditor's Report (continued)
Auditor's Responsibilities for the Audits of the Financial Statements (continued) 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.
Santa Rosa, California
February 13, 2024
CENTRAL COAST COMMUNITY ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
3 The Management’s Discussion and Analysis provides an overview of Central Coast Community Energy’s (3CE) financial activities as of and for the years ended September 30, 2023 and 2022. The information presented here should be considered in conjunction with the audited financial statements.
BACKGROUND
3CE’s formation was made possible in 2002 by the passage of California Assembly Bill 117, which enabled communities to purchase power on behalf of their residents and businesses as an alternative to legacy Investor-Owned Utilities (IOU).
3CE is a Community Choice Aggregator (CCA) established on February 21, 2017 pursuant to Public Utilities Code Section 366.2 and operating as a Joint Powers Authority (JPA) pursuant to Government Code section 6500 et seq. 3CE currently serves residential, commercial and agricultural/industrial customers in communities located within its service area. 1 3CE serves approximately 450,000 customer accounts. 3CE is committed to charging competitive retail generation rates, offering innovative energy programs to facilitate electrification, and reducing greenhouse gas (GHG) emissions through long-term contracts for existing and new utility-scale renewable electricity generation. 3CE has established an innovative procurement strategy to accelerate the reduction of GHG emissions, committing 3CE to developing a resource mix which delivers clean renewable energy for 60% of 3CE’s demand by the year 2025 and 100% of 3CE’s demand by the year 2030.
3CE is governed by a Policy Board and an Operations Board. The Policy Board consists of elected officials from member jurisdictions, while the Operations Board consists of senior staff from those jurisdictions. The Policy Board provides guidance and approval in strategic planning and goal setting, budgets, rates, large capital expenditures, and financing. The Operations Board provides guidance and approval on contracts, agreements, and policies that govern day-to-day operations. 3CE has the rights and powers to set rates for its services, incur debt, and issue bonds or other obligations. 1 As of September 30, 2023, 3CE’s members included the California Cities and Towns of Arroyo Grande, Atascadero, Buellton, Capitola, Carpinteria, Carmel-by-the-Sea, Del Rey Oaks, Goleta, Gonzales, Greenfield, Grover Beach, Guadalupe, Hollister, Marina, Monterey, Morro Bay, Pacific Grove, Paso Robles, Pismo Beach, Salinas, San Juan Bautista, San Luis Obispo, Sand City, Santa Cruz, Santa Maria, Scotts Valley, Seaside, Soledad, Solvang and Watsonville as well as the Counties of Monterey, San Benito, Santa Barbara, San Luis Obispo, and Santa Cruz. 3CE anticipates initiating service in the City of Atascadero and the County of San Luis Obispo in January 2025.
CENTRAL COAST COMMUNITY ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
4 Financial Reporting
3CE presents its financial statements as an enterprise fund under the economic resources measurement focus and accrual basis of accounting, in accordance with Generally Accepted Accounting Principles (GAAP) for proprietary funds, as prescribed by the Governmental Accounting Standards Board (GASB).
Contents Of This Report
This report is divided into the following sections:
Management’s discussion and analysis.
The Basic Financial Statements:
o The Statements of Net Position include all of 3CE’s assets, liabilities, and net position and provides information about the nature and amounts 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 asset acquisitions 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, 2023 AND 2022
5 FINANCIAL HIGHLIGHTS
The following table is a summary of 3CE’s assets, liabilities, and net position, and a discussion of significant changes for the years ended September 30:
2023 2022 2021
Current assets 324,238,888 $ 259,993,090 $ 229,102,332 $ Noncurrent assets
Capital and lease assets, net 2,008,218 219,319 328,942 Other noncurrent assets 1,543,979 1,731,180 79,280
Total noncurrent assets 3,552,197 1,950,499 408,222
Total assets 327,791,085 261,943,589 229,510,554
Current liabilities 54,996,528 45,601,781 32,490,845
Noncurrent liabilities 30,923,232 9,131,250 7,031,250
Total liabilities 85,919,760 54,733,031 39,522,095
Net position
Net investment in capital assets 520,678 219,319 328,942 Restricted for security collateral 294,000 294,000 294,000 Unrestricted 241,056,647 206,697,239 189,365,517
Total net position 241,871,325 $ 207,210,558 $ 189,988,459 $ Current Assets
Current assets were approximately $324,239,000 at the end of 2023 and consist of cash, accounts receivable, accrued revenue, investments, and deposits. Accrued revenue is revenue from energy delivered but not invoiced to customers at year-end. Accounts receivable represents energy delivered and invoiced but not paid for by customers. Total current assets increased each year as a result of 3CE’s operating surplus for each year.
CENTRAL COAST COMMUNITY ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
6 Noncurrent Assets
Capital assets are reported net of depreciation. Changes during the years include acquisition of furniture and equipment, leasehold improvements, and software, less depreciation and amortization. 3CE does not own assets used for electricity generation, transmission or distribution.
A lease asset is reported in accordance with Governmental Accounting Standards Board No. 87 (GASB 87). 3CE entered into a lease in October 2022 for its office space, which accounts for the increase in capital and lease assets.
Other noncurrent assets consist of the long-term portion ($1,521,000) of a $2,000,000 loan made in 2022 to the County of Santa Cruz regarding their acquisition of generator equipment.
Also included in other noncurrent assets are deposits for regulatory and other operating purposes.
Current Liabilities
Current liabilities of approximately $54,997,000 as of September 30, 2023 consist primarily of the cost of electricity delivered to customers that is due to be paid by 3CE after the fiscal year. Current liabilities also include amounts owed for trades payable, personnel costs, taxes and surcharges owed to other governments, and deposits received from suppliers.
Accrued cost of electricity increased each year compared to the prior year. This was a result of increased prices of electricity purchased as well as a small increase in the volume of purchased electricity outstanding. Additionally, current liabilities increased significantly in 2023 due to deposits received from energy suppliers.
Noncurrent Liabilities
The increase in noncurrent liabilities in 2023 is the result of several energy supply contracts entered into or negotiated during the year that required the suppliers to post collateral. These deposits are held by 3CE until certain contract milestones are met or contracts are completed. As part of its risk management policy, 3CE requires energy suppliers to post collateral deposits in some cases. Deposits are determined to be a noncurrent liability if they are not expected to be returned to the supplier within one year of the financial statement date.
CENTRAL COAST COMMUNITY ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
7 Summary of Revenues, Expenses, and Changes in Net Position The following table is a summary of 3CE’s results of operations and a discussion of significant changes for the years ended September 30:
2023 2022 2021
Operating revenues 451,619,272 $ 401,698,835 $ 287,931,441 $ Nonoperating revenues 9,635,091 3,800,219 702,036
Total income 461,254,363 405,499,054 288,633,477
Operating expenses 426,540,098 388,276,955 257,383,668
Nonoperating expenses 53,498 - -
Total expenses 426,593,596 388,276,955 257,383,668
Change in net position 34,660,767 $ 17,222,099 $ 31,249,809 $ Operating Revenues
Rate increases in effect during 2023 account for the majority of the increase in revenue compared to 2022.
Revenues from electricity sales increased from 2021 to 2022 by approximately $111,219,000 as a result of both 3CE’s customer base coming entirely online for the full year in 2022, and rate increases that went into effect during the year.
Nonoperating Revenues
The 2023 increase in nonoperating revenues is a result of increased investment returns related to an increase in market interest rates. The increase from 2021 to 2022 was primarily the result of grant income from the California Arrearage Payment Plan (CAPP) that was received in 2022.
Operating Expenses
3CE’s largest operating expense continues to be the purchase of electricity delivered to its customers. 3CE purchases energy products from markets and is developing a balanced and diversified renewable power portfolio. Operating expenses increased each year due to an increase in the number of customers and rising market prices.
CENTRAL COAST COMMUNITY ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
8 ECONOMIC OUTLOOK
The fiscal year ended September 30, 2023 was a year of stable operations and growing cost pressures from increased costs of energy and resource adequacy compliance. 3CE serves over 450,000 residential, commercial, and agricultural/industrial customer meters in a service area spanning five counties: Santa Cruz, Monterey, San Benito, San Luis Obispo, and Santa Barbara. 3CE serves approximately 94% of all eligible customers in the service area, and that rate of participation is expected to remain stable in 2024.
Operating revenues grew over $49,900,000, driven primarily by the rate adjustments to reflect the increased cost of energy. Operating expenses, comprised primarily of energy costs, increased by approximately $38,300,000 due to a combination of rising energy and resource adequacy (RA) costs, and delays in new power projects resulting from interconnection delays, supply chain, and inflationary pressures. Even with the rising energy and RA compliance costs, the net position grew by almost $34,700,000 over the prior year.
Over time, 3CE’s growing portfolio of renewable energy and storage is expected to lower the cost and volatility of the energy it supplies to customers, helping it maintain a robust financial position.
The portfolio continues to include Power Purchase Agreements (PPAs). Six projects supported by PPAs are online as of fiscal year 2022-23. 3CE’s non-energy administrative costs, including contract services, staffing, and general and administrative expenses, were 6% of revenue, reflecting 3CE’s focus on delivering value for customers.
3CE has implemented cost-based rates that ensure customers pay what it costs to serve them and keeps 3CE competitive with legacy Investor-Owned Utility (IOU) rates. Fiscal year 2022-23 was the second year with cost-based rates for the Pacific Gas and Electric (PG&E) service area. This approach led to significant average customer savings versus IOU rates and will continue to do so in 2024. These savings strengthen 3CE’s competitive position. 3CE will explore expanding the cost based rate approach to its Southern California Edison service area anticipated to start in 2025.
Investments from the Inflation Reduction Act, a renewed political focus on developing new renewable resources, and the significant compliance value in battery storage provide an opportunity for 3CE to continue providing new resources at cost competitive rates. 3CE will continue investing in renewable innovation and initiatives to reach 100% clean and renewable energy through the commitment to new, emerging, scalable technologies and programs.
Management intends to continue its conservative use of financial resources and continues to build credit capacity through increased cash reserves, complying with the energy risk management policy, and entering into favorable energy purchase commitments. As a result, 3CE’s financial position and foundation remain strong and positioned for continued success.
CENTRAL COAST COMMUNITY ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
9 REQUEST FOR INFORMATION
This financial report is designed to provide 3CE’s customers and creditors with a general overview of the organization’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 70 Garden Court, Suite 300, Monterey, CA 93940.
Respectfully submitted,
Robert Shaw, Chief Executive Officer
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, 2023 AND 2022
2023 2022
Current assets
Cash and cash equivalents - unrestricted 195,739,869 $ 150,096,869 $ Accounts receivable, net of allowance 32,759,275 47,107,600 Accrued revenue 24,865,108 18,161,946
Other receivables 4,273,462 2,003,955
Loan receivable 187,201 292,002
Prepaid expenses 380,211 308,419
Deposits 6,494,094 8,293,930
Cash - restricted 294,000 294,000
Investments 59,245,668 33,434,369
Total current assets 324,238,888 259,993,090
Noncurrent assets
Deposits 23,182 23,182
Loan receivable 1,520,797 1,707,998
Lease asset, net of amortization 1,426,467 -
Capital assets, net of depreciation and amortization 581,751 219,319 Total noncurrent assets 3,552,197 1,950,499
Total assets 327,791,085 261,943,589
Current liabilities
Accrued cost of electricity 48,922,476 40,074,582
Accounts payable 2,777,101 1,589,211
Other accrued liabilities 741,801 1,996,024
User taxes and energy surcharges due to other governments 1,753,727 1,941,964 Lease liability 300,423 -
Security deposits - energy suppliers 501,000 -
Total current liabilities 54,996,528 45,601,781
Noncurrent liabilities
Security deposits - energy suppliers 29,756,280 9,131,250 Lease liability 1,166,952 -
Total noncurrent liabilities 30,923,232 9,131,250
Total liabilities 85,919,760 54,733,031
Net investment in capital assets 520,678 219,319
Restricted for security collateral 294,000 294,000
Unrestricted 241,056,647 206,697,239
Total net position 241,871,325 $ 207,210,558 $
NET POSITION
ASSETS
LIABILITIES
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, 2023 AND 2022
2023 2022
OPERATING REVENUES
Electricity sales, net 450,713,404 $ 399,149,960 $
Liquidated damages 750,000 2,548,875
Other income 155,868 -
Total operating revenues 451,619,272 401,698,835
OPERATING EXPENSES
Cost of electricity 398,746,769 366,610,134
Contract services 10,820,099 9,288,170
Staff compensation 6,200,592 6,089,226
Program incentives 8,484,775 4,374,729
Other operating expenses 1,869,295 1,826,016
Depreciation and amortization 418,568 88,680
Total operating expenses 426,540,098 388,276,955
Operating income 25,079,174 13,421,880
NONOPERATING REVENUES (EXPENSES)
Interest and investment returns 8,184,122 1,040,759
Grant revenue 1,450,969 2,759,460
Financing costs (53,498) -
Nonoperating revenues 9,581,593 3,800,219
CHANGE IN NET POSITION 17,222,099 34,660,767
Net position at beginning of year 207,210,558 189,988,459 Net position at end of year 241,871,325 $ 207,210,558 $
CENTRAL COAST COMMUNITY ENERGY
The accompanying notes are an integral part of these financial statements. 12
STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
2023 2022
CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from customers 466,288,740 $ 398,416,283 $
Receipts of liquidated damages 897,000 2,401,875
Other operating receipts 155,868 -
Receipts of deposits and collateral 53,684,900 11,219,952 Payments to suppliers for electricity (392,088,215) (345,208,662) Payments of deposits and collateral (30,759,035) (17,376,728) Payments for other goods and services (12,022,290) (10,922,374) Payments for program incentives (7,797,967) (4,196,754) Payments of staff compensation (6,467,227) (6,178,169)
Payments of taxes and energy surcharges to other governments (8,274,859) (6,812,737) Net cash provided by operating activities 63,616,915 21,342,686
CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES
Grant revenue 1,450,969 2,759,460
CASH FLOWS FROM CAPITAL AND RELATED
FINANCING ACTIVITIES
Payments of lease liability (264,318) -
Payments to acquire capital assets (509,105) (1,113)
Net cash used by capital and related financing activities (773,423) (1,113)
CASH FLOWS FROM INVESTING ACTIVITIES
Investment income received 7,060,790 970,035
Proceeds from investment sales 111,223,174 -
Principal payments received on loan receivable 292,002 - Purchase of investments (137,227,427) (32,418,822)
Loan issued - (2,000,000)
Net cash used by investing activities (18,651,461) (33,448,787) Net change in cash and cash equivalents 45,643,000 (9,347,754) Cash and cash equivalents at beginning of year 150,390,869 159,738,623 Cash and cash equivalents at end of year $ 150,390,869 196,033,869 $ Reconciliation to the Statement of Net Position
Cash and cash equivalents - unrestricted 195,739,869 $ 150,096,869 $ Cash - restricted 294,000 294,000
Cash and cash equivalents 196,033,869 $ 150,390,869 $
SUPPLEMENTAL CASH FLOW INFORMATION
Capital asset acquisitions included in accounts payable and other liabilities 20,165 $ -
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, 2023 AND 2022
2023 2022
Operating income 25,079,174 $ 13,421,880 $
Adjustments to reconcile operating income to net
cash provided by operating activities
Depreciation and amortization expense 418,568 88,680
(Increase) decrease in:
Accounts receivable, net of allowance 14,348,325 (9,731,301) Accrued revenue (6,703,164) 1,849,150
Energy settlements receivable - 7,856,108
Other receivables (1,913,221) (1,069,449)
Prepaid expenses (71,792) 1,251,830
Deposits 1,799,836 (6,575,149)
Increase (decrease) in:
Accrued cost of electricity 8,847,894 11,425,158
Accounts payable 1,167,725 357,493
Other accrued liabilities (294,223) (115,044)
User taxes and surcharges due to other governments (188,237) 483,330 Security deposits - energy suppliers 21,126,030 2,100,000 Net cash provided by operating activities 63,616,915 $ 21,342,686 $
RECONCILIATION OF OPERATING INCOME TO NET
CASH PROVIDED BY OPERATING ACTIVITIES
CENTRAL COAST COMMUNITY ENERGY
NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
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, 2023:
Counties Cities and Towns
Monterey Arroyo Grande Morro Bay
San Benito Atascadero Pacific Grove
Santa Barbara Buellton Paso Robles
Santa Cruz Capitola Pismo Beach
Carpinteria Salinas
Carmel-by-the-Sea 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 Boards, a Policy Board and an Operations Board. Each Board is comprised of 17 members with 17 alternates representing the participating communities. Some of the 17 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 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, 2023 AND 2022
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: 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. 3CE has cash that is restricted under various security agreements. This is reported as restricted cash on the Statements of Net Position and is included in cash and cash equivalents for the purpose of the Statements of Cash Flows.
PREPAID EXPENSES AND 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. Also included are prepaid expenses and deposits for regulatory and other operating purposes.
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. 3CE’s Investment Policy permits the investment of funds in depository accounts, certificates of deposit and the Local Agency Investment Fund (LAIF) program operated by the California State Treasury, United States Treasury obligations, Federal Agency Securities, commercial paper, and money market funds.
CENTRAL COAST COMMUNITY ENERGY
NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
16 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
LEASE ASSET AND LEASE LIABILITY
3CE recognizes an asset and liability when it enters into certain leasing arrangements. 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 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 and seven years for furniture and leasehold improvements. 3CE does not own any electric generation, transmission or distribution assets.
SECURITY DEPOSITS-ENERGY SUPPLIERS
Various energy 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.
NET POSITION
Net position is presented in the following components:
Net investment in capital assets: This component of net position consists of capital assets, lease asset, net of accumulated depreciation and amortization, and reduced by outstanding borrowings that are attributable to the acquisition, construction, or improvement of those assets.
Restricted for security collateral: This component of net position consists of constraints placed on net asset use through external constraints imposed by creditors (such as through debt covenants), grantors, contributors, or laws or regulations of other governments or constraints imposed by law through constitutional provisions or enabling legislation.
Unrestricted: This component of net position consists of net position that does not meet the definition of “net investment in capital assets” or “restricted for security collateral.”
CENTRAL COAST COMMUNITY ENERGY
NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
17 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
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 on 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.
OPERATING AND NONOPERATING EXPENSES
Operating expenses include the costs of electricity, staffing, contractor services, program incentives, and other operating expenses. Expenses not meeting this definition are reported as nonoperating expenses.
ELECTRICAL POWER PURCHASED
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 as well as 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.
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 generators to comply with the California Public Utility Commission’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 grid in real-time and to provide appropriate incentives for the siting and construction of new resources needed for reliability in the future.
CENTRAL COAST COMMUNITY ENERGY
NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
18 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
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.
INCOME TAXES
3CE is a Joint Powers Authority under the provision of the California Government Code and is not subject to federal or state income or franchise taxes.
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 previously reported net position or change in net position.
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.
CENTRAL COAST COMMUNITY ENERGY
NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
19 3. RECEIVABLES AND DEPOSITS
ACCOUNTS RECEIVABLE
Accounts receivable were as follows as of September 30:
2023 2022
Accounts receivable from customers 43,313,058 $ 55,979,470 $ Allowance for uncollectible accounts (10,553,783) (8,871,870) Net accounts receivable 32,759,275 $ 47,107,600 $
The majority of account collections occur within the first few months following customer invoicing. 3CE estimates that a portion of the billed 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 amounts billed during the current and prior fiscal years. During 2023 and 2022, 3CE recorded $6,864,000 and $6,192,000, respectively, as an increase to the allowance in anticipation of uncollectible accounts. Bad debt expense is reported as a reduction in electricity sales on 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. In 2023 and 2022, 3CE received CAPP funds (see Note 6) that helped recover for previously written off accounts receivable.
OTHER RECEIVABLES
Other receivables consists 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 $6,517,000 and $8,317,000 as of September 30, 2023 and 2022, 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. Also included in current assets are 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, 2023 AND 2022
20 4. INVESTMENTS
During the years ended September 30, 2023 and 2022, 3CE purchased investments with original maturities of three months or more. As of September 30, investments were as follows:
2023 2022
Investments at Fair Value:
Commercial paper 3,700,088 $ 2,435,226 $
U.S. government & agency obligations 45,545,580 14,584,200 Municipal obligations - 3,863,262
Total investments at fair value 49,245,668 20,882,688
Certificate of deposits 10,000,000 12,551,681
Total investments 59,245,668 $ 33,434,369 $
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, 2023 and 2022, 3CE’s investments are considered Level 1 inputs, except for certificates of deposits, which are based on the nominal value. Quoted prices in active markets were used for determining fair value measurement.
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 for other investments is not available.
3CE’s investment policy addresses this risk. 3CE limits investments to those allowed by Section 53601 of the California Government Code that addresses the risk allowable for each investment.
CENTRAL COAST COMMUNITY ENERGY
NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
21 4. INVESTMENTS (continued)
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, 2023 and 2022, 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.
INTEREST RATE RISK
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.
All investments had a maturity of less than one year as of September 30, 2023 and 2022. 3CE intends to hold investments to maturity.
CENTRAL COAST COMMUNITY ENERGY
NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
22 5. CAPITAL ASSETS AND LEASE ASSET
Capital asset activity for the years ended September 30, 2023 and 2022 was as follows:
Furniture &
Equipment
Leasehold
Improvements Software
Accumulated
Depreciation
and
Amortization Total
Balances at September 30, 2021 598,432 $ 80,743 $ - $ (350,233) $ 328,942 $ Additions 1,113 - - (88,680) (87,567)
Dispositions - (22,056) - - (22,056)
Balances at September 30, 2022 599,545 58,687 - (438,913) 219,319 Additions 97,171 31,974 400,126 (166,838) 362,432
Balances at September 30, 2023 696,716 $ 90,661 $ 400,126 $ (605,751) $ 581,751 $ Lease asset activity for the years ended September 30, 2023 and 2022 was as follows:
Lease Asset
Accumulated
Amortization Total
Balances at September 30, 2021 - $ - $ - $
Additions - - -
Dispositions - - -
Balances at September 30, 2022 - - -
Additions 1,678,197 (251,730) 1,426,467
Dispositions - - -
Balances at September 30, 2023 1,678,197 $ (251,730) $ 1,426,467 $
6. GRANT REVENUE
3CE administers 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. In 2022 this program was funded through the federal American Rescue Plan Act (ARPA) with Coronavirus State and Local Fiscal Recovery Funds. The program was funded by the State of California in 2023. Grant revenue recognized for the years ended September 30, 2023 and 2022 was $1,451,000 and $2,759,000, respectively.
CENTRAL COAST COMMUNITY ENERGY
NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
23 7. 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). As of September 30, 2022, there were 34 plan participants. 3CE is required to contribute 10% of covered payroll as a match to required employee contributions. 3CE contributed approximately $502,000 and $462,000 for the years ended September 30, 2023 and 2022, respectively. Plan provisions and contribution requirements as they apply to 3CE are established and may be amended by the Board of Directors. 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.
8. 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.
CENTRAL COAST COMMUNITY ENERGY
NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
24 9. 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, 2023:
Year ending September 30,
2024 496,000,000 $
2025 344,000,000
2026 196,000,000
2027 191,000,000
2028 186,000,000
2029-2053 2,755,000,000
Total 4,168,000,000 $
CENTRAL COAST COMMUNITY ENERGY
NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
25 10. LEASES
A lease asset is reported in accordance with Governmental Accounting Standards Board No. 87 (GASB 87). According to GASB, the Statement aims to increase the usefulness of governments’ financial statements by requiring reporting of certain lease assets and liabilities that previously were not recognized on the statement of net position.
On October 27, 2022, 3CE entered into a 3-year non-cancelable lease commencing on January 1, 2023 for its office premises. The rental agreement includes an option to renew the lease for two additional one-year terms.
Rental payments under this lease were $330,000 for the year ended September 30, 2023.
As of September 30, 2023, future minimum lease payments under this lease were as follows:
Year ending September 30, Principal Interest Total
2024 300,423 $ 59,931 $ 360,354 $
2025 325,259 45,905 371,164
2026 351,568 30,731 382,299
2027 379,426 14,342 393,768
2028 110,699 878 111,577
Total 1,467,375 $ 151,787 $ 1,619,162 $
26 CENTRAL COAST COMMUNITY ENERGY
NOTES TO THE BASIC FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2023 AND 2022
11. JOINT VENTURE
3CE participates in a joint powers agreement (JPA) through the California Community Choice Financing Authority (CCCFA). CCCFA was formed as a conduit issuer to assist its members by undertaking the financing or refinancing of energy prepayments that can be financed with 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.
In December 2023, CCCFA issued bonds in the amount of $647,750,000, excluding original issue premium, the proceeds of which to be used to finance energy purchases that will be delivered to 3CE.
No debt, liability, or obligation of CCCFA is a debt, liability, or obligation of 3CE. 3CE will purchase energy from CCCFA in the same manner as it purchases energy from other suppliers. 3CE did not purchase any energy from CCCFA during fiscal year 2023. The outstanding purchase commitments related to these financing facilities are included in Note 9.
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 2023, and 2022, 3CE contributed approximately $18,000 and $28,000, 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, 2023:
GASB has approved GASB Statement No. 100, Accounting Changes and Error Corrections – An Amendment of GASB Statement No. 62, and GASB Statement No. 101, Compensated Absences. Management is evaluating the effect of implementation of these statements.
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 and a supplemental budgetary comparison schedule for the period ended September 30, 2023, 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
November 13, 2023
1101 Fifth Avenue, Suite 200 San Rafael, CA 94901 415 459 1249 mahercpa.com
2022/23 YTD
Budget (Amended)
2022/23 YTD
Actual
2022/23 YTD
Budget Variance
(Under) Over
2022/23 YTD
Actual / Budget %
2022/23 Annual
Budget (Amended)
2022/23 Budget
Less Actual
2022/23 Budget
Remaining /
Budget %
REVENUES AND OTHER SOURCES
Electricity sales 463,110,000 $ 459,028,029 $ (4,081,971) $ 99% 463,110,000 $ 4,081,971 $ 1% Uncollectible accounts (7,500,000) (6,863,656) 636,344 92% (7,500,000) (636,344) 8% Net revenue - electricity 455,610,000 452,164,373 (3,445,627) 99% 455,610,000 3,445,627 1% Investment and miscellaneous income 6,187,000 8,339,990 2,152,990 n/a 6,187,000 (2,152,990) n/a Total revenues and other sources 461,797,000 461,254,363 (542,637) 100% 461,797,000 542,637 0% EXPENDITURES AND OTHER USESCurrent Expenditures
Cost of energy 398,884,224 403,427,000 (4,542,776) 99% 403,427,000 4,542,776 1% Energy programs (incentives and grants) 15,920,000 9,266,438 (6,653,562) 58% 15,920,000 6,653,562 42% Data manager 2,967,678 2,975,000 (7,322) 100% 2,975,000 7,322 0% Utility service fees 1,808,000 1,831,586 23,586 101% 1,808,000 (23,586) -1% Staffing 9,191,000 6,200,593 (2,990,407) 67% 9,191,000 2,990,407 33% Professional services 3,317,000 2,151,323 (1,165,677) 65% 3,317,000 1,165,677 35% Legal services 1,860,000 1,223,252 (636,748) 66% 1,860,000 636,748 34% Marketing and customer enrollment 717,428 951,000 (233,572) 75% 951,000 233,572 25% Other general & administration 3,599,000 2,133,615 (1,465,385) 59% 3,599,000 1,465,385 41% Total current expenditures 443,048,000 425,376,137 (17,671,863) 96% 443,048,000 17,671,863 4% Other Uses
Capital outlay 203,000 129,142 (73,858) n/a 203,000 73,858 n/a Total other uses 203,000 129,142 (73,858) n/a 203,000 73,858 Total expenditures and other uses 443,251,000 425,505,279 (17,745,721) 96% 443,251,000 17,745,721 4% Surplus (Deficit) 18,546,000 $ 35,749,084 $ 17,203,084 $ 18,546,000 $ (17,203,084) $ -93% Reserves at end of reporting period: Held for working capital 50,200,000 $ Held for reserves - cash and cash equivalents 140,839,869 Held for reserves - investments 59,245,668 Total 250,285,537 $
CENTRAL COAST COMMUNITY ENERGY
SUPPLEMENTAL BUDGETARY COMPARISON SCHEDULE
Year Ended September 30, 2023
CCA Program Surplus/(Deficit)
per budgetary comparison schedule: 35,749,084 $
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 210,822 Subtract depreciation expense (418,568)
Add back capital asset acquisitions 529,270
Change in Net Position 36,070,608 $
REVENUES, EXPENSES AND CHANGES IN NET POSITION
CENTRAL COAST COMMUNITY ENERGY
BUDGET RECONCILIATION TO STATEMENT OF
Year Ended September 30, 2023
Budget Item YTD Variance Comment
Electric Sales Revenue (0.9%) 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 (1.1%) 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 (32.5%) Staffing expenses are under budget due to the timing of new hires.
Professional Services (35.1%) This category includes accounting, IT, technical and other consultants.
Legal Costs (34.2%) This category includes outside legal costs for regulatory and energy procurement needs.
Marketing and customer enrollment (24.6%) Variance is mostly due to the lower than anticipated costs of recent customer enrollments.
Data Management Services (0.2%) These fees non-discretionary and are charged on a per customer basis.
Utility Service Fees 1.3% These are PG&E and SCE fees charged on a per customer basis.
Other General & Administrative (40.7%) This category includes occupancy costs, industry membership dues, and other general and administrative costs.
Energy and Related Programs (41.8%) Programs expenses have generally been delayed until future periods Budget Commentary for significant items
CENTRAL COAST COMMUNITY ENERGY
October 1, 2022 through September 30, 2023