Supplemental Packet — MCE Executive Committee, February 2, 2026

MCE Executive Committee Meeting
Monday, February 2, 2026
12:00 p.m.
1125 Tamalpais Avenue, San Rafael, CA 94901
2300 Clayton Road, Suite 1500, Concord, CA 94520
250 East L Street, Benicia, CA 94510, Conference Room 2 (City of Benicia) 955 School Street, Napa, CA 94559, City Hall Committee Room (City of Napa) Public comments may be made in person or remotely via the details below.

Remote Public Meeting Participation
Video Conference: https://t.ly/DnY7U
Phone: Dial (669) 900-9128, Meeting ID: 861 2234 3784, Passcode: 415565 Materials related to this agenda are available for physical inspection at MCE’s offices in San Rafael at 1125 Tamalpais Avenue, San Rafael, CA 94901 and in Concord at 2300 Clayton Road, Suite 1500, Concord, CA 94520.

DISABLED ACCOMMODATION: If you are a person with a disability who requires an accommodation or an alternative format, please contact MCE at (888) 632-3672 or [email protected] at least 72 hours before the meeting start time to ensure arrangements are made.

Agenda Page 1 of 2

1. Roll Call/Quorum

2. Board Announcements (Discussion)

3. Public Open Time (Discussion)

4. Report from Chief Executive Officer (Discussion)

5. Consent Calendar
C. 1. Approval of 1.5.26 Meeting Minutes (Action)
C. 2. Approval 1.9.26 Continuation Meeting Minutes (Action) Agenda Page 2 of 2
C. 3. Review Draft 2.19.26 Board Agenda (Action)

6. Selection of Executive Committee Chair (Discussion/Action)

7. Integrated Resource Plan Review (Discussion)

8. MCE Rate Reduction Proposals (Discussion/Action)

9. Proposed Fiscal Year 2026/27 Budget Elements (Discussion)

10. Voting Processes in the Operating Rules & Regulations: General Admin Matters and Matters that relate to the CCA (Discussion)

11. Committee & Staff Matters (Discussion)

12. Adjourn
The Executive Committee may discuss and/or take action on any or all of the items listed on the agenda irrespective of how the items are described.

DRAFT

MCE EXECUTIVE COMMITTEE MEETING MINUTES
January 5, 2026
12:00 P.M.

Present: Stephanie Andre, City of Larkspur
Cindy Darling, City of Walnut Creek
Stephanie Hellman, Alternate, Town of Fairfax
Devin Murphy, City of Pinole, arrived at 12:32 p.m.

Laura Nakamura, City of Concord
Max Perrey, City of Mill Valley, Chair
Shanelle Scales-Preston, County of Contra Costa
Sally Wilkinson, City of Belvedere

Absent: Eli Beckman, Town of Corte Madera
Maika Llorens Gulati, City of San Rafael
Gabriel Quinto, City of El Cerrito
Staff
& Others: Jared Blanton, VP of Public Affairs
Jesica Brooks, Lead Board Clerk and Executive Assistant Vicken Kasarjian, Chief Operations Officer
Tanya Lomas, Board Clerk
Linda Lye, Senior Legal Counsel
Catalina Murphy, General Counsel
Ashley Muth, Internal Operations Associate
Justine Parmelee, VP of Internal Operations
Zae Perrin, VP of Customer Operations
Mike Rodriguez-Vargas, Internal Operations Assistant
Dan Settlemyer, Internal Operations Associate
Sabrinna Soldavini, VP of Policy
Maíra Strauss, Chief Financial Officer
Jamie Tuckey, Chief Customer Officer
Dawn Weisz, Chief Executive Officer

1. Roll Call
Chair Perrey called the regular Executive Committee meeting to order at 12:03 p.m. with quorum established by roll call.

2. Board Announcements (Discussion)
There were no comments.

DRAFT

3. Public Open Time (Discussion)
Chair Perrey opened the public comment period and comments were made by members of the public Robert Miller and Jody Timms.

4. Report from Chief Executive Officer (Discussion)
Dawn Weisz, Chief Executive Officer, introduced this item and addressed questions from committee members.

Chair Perrey opened the public comment period and there were comments made by members of the public Alicia Minyen, Wendy Breckon, and Steven Rosenfeld.

5. Consent Calendar (Discussion/Action)
C.1 Approval of 12.1.25 Meeting Minutes
C.2 Corrections to the Marin Independent Journal and Misinformation C.3 Review Updated Draft 1.15.26 Board Agenda
Director Andre requested that Item C.2 and C.3 be pulled from the consent calendar for discussion. The Chair accepted the request and opened the floor for questions and comments from committee members.

Chair Perrey opened the public comment period and there were comments made by members of the public Dan Segedin, Alicia Minyen, Wendy Breckon, Jody Timms, and MCE Board Director for the City of Napa, Beth Painter.

Action 1: It was M/S/C (Wilkinson/Nakamura) to approve Consent Calendar item C.1. Motion carried by roll call vote. 7-Yays 1-Abstain. (Abstain: Hellman.

Absent: Beckman, Llorens-Gulati, and Quinto).

Action 2: It was M/S/C (Murphy/Scales-Preston) to approve item C.2 with amendments from Committee members to the Board of Directors for consideration. Motion carried by roll call vote. 6-Yays 1-No 1- Abstain. (No:

Andre. Abstain: Wilkinson. Absent: Beckman, Llorens-Gulati, and Quinto).

Action 3: It was M/S/C (Andre/Wilkinson) to move the voting process discussion up to item number 5 on Item C.3, Board Agenda for January 15, 2026. Motion did not carry. 4-Yays 4-Nos. (Nos: Darling, Murphy, Nakamura, and Scales-Preston. Absent: Beckman, Llorens-Gulati, and Quinto).

Action 4: It was M/S/C (Nakamura/Darling) to approve Item C.3 as published. Motion carries by roll call vote. 6-Yays 2-Nos. (Nos: Andre and Wilkinson. Absent: Beckman, Llorens-Gulati, and Quinto).

DRAFT
Adjournment
The MCE Executive Committee Meeting of January 5, 2026 adjourned at 4:31p.m., to a future to-be-determined date, time, and place to discuss the remaining business of the Executive Committee items posted in the agenda for the meeting of January 5, 2026. The Notice of Adjournment was posted by MCE's Clerk on January 6, 2026, stating the Executive Committee Meeting would continue on January 9, 2026, at 1:00pm at 1125 Tamalpais Ave. San Rafael, CA. 94901 and 2300 Clayton Rd, Concord, CA. 94520.
___________________________________________
Max Perrey, Chair
Attest:
___________________________________________
Dawn Weisz, Secretary
DRAFT

MCE EXECUTIVE COMMITTEE CONTINUATION MEETING MINUTES
January 9, 2026
1:00 P.M.

Present: Stephanie Andre, City of Larkspur
Eli Beckman, Town of Corte Madera, joined at 1:11 p.m.

Barbara Coler, Town of Fairfax
Cindy Darling, City of Walnut Creek
Maika Llorens Gulati, City of San Rafael
Laura Nakamura, City of Concord, left at 3:24 p.m.

Max Perrey, City of Mill Valley, Chair
Shanelle Scales-Preston, County of Contra Costa
Sally Wilkinson, City of Belvedere

Absent: Devin Murphy, City of Pinole
Gabriel Quinto, City of El Cerrito
Staff
& Others: Jared Blanton, VP of Public Affairs
Jesica Brooks, Lead Board Clerk and Executive Assistant Vicken Kasarjian, Chief Operations Officer
Tanya Lomas, Board Clerk
Linda Lye, Senior Legal Counsel
Catalina Murphy, General Counsel
Ashley Muth, Internal Operations Associate
Justine Parmelee, VP of Internal Operations
Zae Perrin, VP of Customer Operations
Mike Rodriguez-Vargas, Internal Operations Assistant
Dan Settlemyer, Internal Operations Associate
Sabrinna Soldavini, VP of Policy
Maíra Strauss, Chief Financial Officer
Jamie Tuckey, Chief Customer Officer
Dawn Weisz, Chief Executive Officer
Roll Call
Chair Perrey called the regular Executive Committee meeting to order at 1:00 p.m. with quorum established by roll call.

6. Update on Power Charge Indifference Adjustment and CPUC Engagement (Discussion)
Sabrinna Soldavini, VP of Policy, presented this item and addressed questions from Committee members.

DRAFT
Chair Perrey opened the public comment period and there were no comments.

7. Potential Scope of Finance Committee (Discussion/Action) Justine Parmelee, VP of Internal Operations, presented the draft scope for Committee members to discuss.

Chair Perrey opened the public comment period and there was a comment made by member of the public Dan Segedin.

Action: It was M/S/C (Llorens-Gulati/Scales-Preston) to recommend to the Board of Directors approval of the Finance Committee Scope as edited.

Motion carried by unanimous roll call vote. (Absent: Murphy and Quinto).

8. Committee & Staff Matters (Discussion)
There were no comments.

9. Adjournment
Chair Perrey adjourned the meeting at 3:28 p.m. to the next scheduled Executive Committee Meeting on February 2, 2026.
___________________________________________
Max Perrey, Chair
Attest:
___________________________________________
Dawn Weisz, Secretary
DRAFT
MCE Board of Directors Meeting
Thursday, February 19, 2026
6:30 p.m.
1125 Tamalpais Avenue, San Rafael, CA 94901
2300 Clayton Road, Suite 1500, Concord, CA 94520
Public comments may be made in person or remotely via the details below.

Remote Public Meeting Participation
Video Conference: https://t.ly/mIv5w
Phone: Dial (669) 900-9128, Meeting ID: 890 0487 7785, Passcode: 525690 Materials related to this agenda are available for physical inspection at MCE’s offices in San Rafael at 1125 Tamalpais Avenue, San Rafael, CA 94901 and in Concord at 2300 Clayton Road, Suite 1500, Concord, CA 94520.

DISABLED ACCOMMODATION: If you are a person with a disability who requires an accommodation or an alternative format, please contact MCE at (888) 632-3674 or [email protected] at least 72 hours before the meeting start time to ensure arrangements are made.

Agenda Page 1 of 2

1. Roll Call/Quorum

2. Board Announcements (Discussion)

3. Public Open Time (Discussion)

4. Report from Chief Executive Officer (Discussion)

5. Consent Calendar
C.1. Approval of 1.15.26 Meeting Minutes (Action)
C.2. Addition of Board Members to Committees (Action)
Agenda Page 2 of 2
C.3. Approved Contracts for Energy Update (Information) C.4. Quarterly Marketing Update (Information)
C.5. Legislative and Regulatory Update (Information)

6. Resolution 2026-01 Teleconferencing (Discussion/Action)

7. MCE Rate Reduction Proposal, Effective April 1, 2026 (Discussion/Action)

8. Proposed FY 2026/27 Budget Elements (Discussion)

9. Resolution 2020-04 Review (Discussion)

10. Board & Staff Matters (Discussion)

11. Adjourn
The Board of Directors may discuss and/or take action on any or all of the items listed on the agenda irrespective of how the items are described.
2026 MCE Board Offices and Committee Rosters

BOARD OFFICES
Chair: Shanelle Scales-Preston, County of Contra Costa
Vice Chair: Cindy Darling, Walnut Creek
Treasurer: Maira Strauss, MCE Chief Financial Officer
Secretary: Dawn Weisz, MCE Chief Executive Officer

BOARD OFFICES SELECTION PROCESS
The Chair and Vice Chair offices are held for 1 year and there are no limits on the number of terms held by either Chair or Vice Chair.1 The selection of these offices shall take place in or near December of each year.2 The office of Treasurer is appointed by the Board via an approved resolution and may be a non-board member. The Treasurer appointment, along with the delegated authority, is held for 1 year and there are no limits on the number of terms held.3 Deputy Treasurers are appointed directly by the Treasurer each year. Once appointed by the Board, the Secretary shall continue to hold the office each year until the Secretary chooses to resign from the role or the Board decides to remove the individual from the Secretary position.4 The Secretary does not need to be a member of the Board. All officer appointments/selections by the Board require a majority vote of the full membership of the Board.5
EXECUTIVE COMMITTEE (Updated 1.15.26)

1. Stephanie Andre

2. Kari Birdseye

3. Barbara Coler, interested in Vice Chair

4. Cindy Darling, interested in Chair

5. Maika Llorens Gulati

6. Devin Murphy

7. Laura Nakamura

8. Beth Painter

9. Max Perrey, outgoing Chair

10.Shanelle Scales-Preston

11.Sally Wilkinson
City of Larkspur
City of Benicia
Town of Fairfax
City of Walnut Creek
City of San Rafael
City of Pinole
City of Concord
City of Napa
City of Mill Valley
County of Contra Costa
City of Belvedere
1 Section 4.13.1 of MCE Joint Powers Agreement.
2 Article V, Section 1 of MCE’s Operating Rules and Regulations. 3 Article V, Section 1 of MCE’s Operating Rules and Regulations; California Government Code § 53607. 4 Article IV, Section 1(c) of MCE’s Operating Rules and Regulations. 5 Article VI, Section 2 of MCE’s Operating Rules and Regulations. At MCE’s current membership of 38 communities with appointed Directors, the vote needed is 20.

FINANCE COMMITTEE (Updated 1.15.26)

1. Liz Alessio

2. Stephanie Andre

3. John McCormick

4. Charles Palmares

5. Sally Wilkinson
Napa County and four Napa Cities
City of Larkspur
City of Lafayette
City of Vallejo
City of Belvedere
TECHNICAL COMMITTEE (Updated 1.15.26)

1. Devin Murphy, Chair

2. Stephanie Andre, Vice Chair

3. Dion Bailey

4. John McCormick

5. Charles Palmares

6. Amanda Szakats

7. Cesar Zepeda
City of Pinole
City of Larkspur
City of Hercules
City of Lafayette
City of Vallejo
City of Pleasant Hill
City of Richmond
2026 AD HOC CONTRACTS COMMITTEE (Updated 1.15.26)

1. Barbara Coler

2. Devin Murphy
Town of Fairfax
City of Pinole
2026 AD HOC GOVERNANCE COMMITTEE (Updated 1.15.26)

1. Liz Alessio

2. Kari Birdseye

3. Mary Sackett

4. Shanelle Scales-Preston
Napa County and Four Napa Cities
City of Benicia
County of Marin
Contra Costa County
Integrated
Resource
Plan
Review
February 2, 2026
MCE Executive
Committee
What is the IRP?
2 • IRP = Integrated Resource Plan
• Key Goal: Identify a diverse portfolio of resources to meet grid reliability needs & support CA’s Greenhouse Gas
(GHG) emissions reductions goals.
• The IRP is overseen by the California Public Utilities Commission (CPUC) and is the process by which the
CPUC sets resource planning targets for Load Serving
Entities (LSEs) within its jurisdiction.

How Does the IRP Work?
3 The IRP has two tracks which impact MCE procurement, budget, and ratepayers:

1. Planning
• Builds Preferred System Plan (PSP) based on forecasts, policy goals, and statewide emissions targets.
• Load Serving Entities (LSEs) prepare individual plans that are aggregated and evaluated against PSP.

2. Procurement
• CPUC evaluates and determines if there is a need for additional procurement to fill identified shortfalls.
• This can (and has) lead to mandatory procurement orders.

IRP Process Explained
4 1. Load Forecasting:
• CPUC utilizes demand and reliability forecasts from California Energy Commission and CAISO to create long-term (10-20 years) forecast

2. Portfolio Modeling and System Needs
• CPUC models multiple resource portfolios based on requirements (reliability, emissions targets, cost) to identify system needs (capacity, resource types, transmission, etc.)

3. Preferred System Plan
• Utilizes modeling to create long-term procurement blueprint (resource mix, timing, etc.) that meets reliability and emissions targets

4. LSEs Develop Individual Conforming Portfolios
• LSEs allocated share of system plan and required to develop conforming portfolio demonstrating ability to meet state targets
How Does MCE Participate in the IRP
5 • MCE regularly engages in advocacy in CPUC-related proceedings to advocate for reasonable forecast and planning assumptions as well as fair procurement obligations
• Submit IRP plans to the CPUC every two years:
• After development of the PSP, the CPUC allocates portion of the PSP to individual LSEs like MCE
• MCE is required to create and submit a “conforming portfolio” for submission to the CPUC
• Conforming Portfolio outlines MCE’s model demonstrating that it can meet share of statewide reliability need and GHG targets.

MCE’s 2022 IRP (example)
For the 2022 IRP Cycle, MCE developed one
Conforming Portfolio that:
• Included plans for:
• 1091 MW of new capacity by 2035
• 85% renewable energy content by 2029
• 12% large hydroelectric energy by 2029
• Was consistent with MCE operational and
policy guidelines (Operational IRP)
• Satisfied all CPUC assigned emissions
limitations, energy, and reliability
requirements
6 MCE’s Procurement Update
7 2022 IRP Conforming Portfolio Projected by 2035 Contracted Capacity** Wind 265 MW 151 MW
Solar+Storage 212 MW Solar/
153 MW Storage
312 MW Solar/
263 MW Storage
Storage 400 MW 415 MW
Geothermal 109 MW 127 MW
Long Duration Storage 90 MW 35 MW
Demand Response 15 MW 15 MW*
* RA only
**Contracted capacity may include new or existing projects Impacts of IRP on MCE
8 • The IRP process is used to demonstrate that MCE can, and plans to, meet reliability and GHG targets as set by the state.
• Directly impacts MCE’s operation strategy and budget:
• Influences and constrains (but does not dictate) MCE’s future procurement efforts
• Can result in procurement mandates if the PUC determines that the state requires new capacity to meet reliability and emissions requirements
• Has a direct (but not 1:1) impact on MCE’s procurement costs  budget and rate impacts for MCE and its customers
IRP Impacts – Past Procurement Orders
9 • 2019 - IRP Procurement Order (D.19-11-016)
• Ordered 3,300 MW of new capacity by 2023 in tranches
• MCE share: 87.5 MW of Qualifying Capacity*
• 2021 - Mid Term Reliability (MTR) Order (D.21-06-035) • Ordered 11,500 MW of new capacity by 2026 in tranches between 2023 & 2026 and with certain requirements (i.e. Long Lead Time (LLT) Resources, Diablo Canyon Replacement, etc.)
• MCE share: 332 MW of Qualifying Capacity
• 2023 - Supplemental MTR Order (D.23-02-040)
• Ordered an additional 4000 MW to come online between 2026-2027 and extended LLT deadline to June 1, 2028
• MCE share: 122 MW of Qualifying Capacity
* Technology Specific discount factors are applied to Contracted Capacity by the CPUC to calculate Qualifying Capacity.

IRP Impacts – New
Procurement Order • In mid-January, the CPUC issued a
Proposed Decision based on prior
analysis identifying a need for
new capacity to meet state
reliability needs. • Orders 6,000 MW of new
capacity by 2032.
• Require all CPUC-jurisdictional
LSEs to procure proportional
shares of the 6,000 MW from
2029–2032.
• Drivers: Data center load
growth and transportation
electrification.

For MCE,
~60 MW in 2030 &
~120 MW in 2032
10 What IRP Does NOT Do
The IRP does NOT:
• Select individual projects or contracts that MCE must procure • MCE’s procurement authority resides with this Board,
and however the Board delegates such authority.
• All future contracts for resources will continue to follow that approval process.
• Determine specific or exact cost impacts for MCE
• Account for MCE or individual LSEs internal goals and constraints
• Align perfectly with market timing or contract availability to ensure least cost, optimal portfolios for individual LSEs 11 Next Steps
MCE does not
set rates for
electric delivery
or natural gas.
• MCE is beginning to engage in 2026
IRP Cycle
• Just received final templates and
requirements from CPUC
• Currently scheduled to be due
June 1, 2026
• MCE plans to bring IRP to Technical
Committee and Board for approval in
Q2 2026 before submitting to CPUC
12 Thank you!
mceCleanEnergy.org
[email protected]
1 February 2, 2026
TO: MCE Executive Committee
FROM: Maira Strauss, Chief Financial Officer and Treasurer Kaladhar R. Bollampalli, Director of Power Systems & Analytics Jonnie Kipyator, Principal Manager, Power Analytics
RE: MCE Rate Reduction Proposals (Agenda Item #08)
ATTACHMENT: Presentation FY 2026/27 MCE Rate Reduction Proposals

Dear Executive Committee Members:

Summary:

MCE is conducting its annual rate-setting assessment for FY 2026/27. Rates are assessed using six criteria: revenue sufficiency, rate competitiveness, rate stability, customer understanding, equity among customers, and efficiency and conservation.

Power supply costs in the market have dropped in recent months, creating a declining trend in cost of service. This trend is creating headroom in MCE’s generation rates that could allow for a reduction for customers, while still meeting MCE’s revenue requirements in the next fiscal year.

PG&E implemented new generation rates effective January 1, 2026, which are lower than MCE’s current generation rates. At the same time, the Power Charge Indifference Adjustment (PCIA) charged by PG&E to MCE customers (“unbundled customers”) has increased dramatically due to a large PCIA true-up recovering 2025 PG&E under-collections, while bundled customers (customers who take generation service from PG&E) are receiving PCIA credits. This gap stems from a 2025 CPUC decision that retroactively recalculated market price benchmarks, creating an alleged PG&E revenue shortfall that is now being recovered primarily from unbundled customers in 2026.

To better align with MCE’s declining cost of service and to deepen opportunities for customer savings, staff evaluated multiple rate options, reserve-supported rate relief tools, and potential cost-savings from reduction in clean procurement targets.

Staff evaluated five Generation Rate Reduction options for FY 2026/27. Please note:
• Rate comparisons are based on Residential E-TOU-C plan and MCE’s 2017 PCIA vintage. • Residential rates are used for comparison and illustration purposes only; similar rate reductions apply across all customer groups, including commercial, industrial, and other non-residential classes.
• Proposed rate reductions are approximate; actual impacts vary by rate class and time-of-use period.
• Monthly bill impacts assume 438 kWh of typical residential usage. • All figures are estimates and subject to change.

Table 1. Summary of FY 2026/27 Generation Rate Reduction Options.

MCE’s current residential generation rate is 14.62¢/kWh.

Option Generation
Rate
Reduction
Under-Recovery of
Cost
How the Gap Is
Addressed
Residential
Bill Impact
(w/o PCIA)
Residential
Bill Impact
(w/ PCIA)
1 1.73¢/kWh
(12%)
$0M N/A $1 above
bundled
customers
$22 above
bundled
customers
2 2¢/kWh
(14%)
$14M Partial ORF (Rate
Stabilization Fund)
$0 below
bundled
customers
$21 above
bundled
customers
3 3¢/kWh
(21%)
$67M Almost full ORF $4 below
bundled
customers
$17 above
bundled
customers
4 3.51¢/kWh
(24%)
$94M Full ORF + Reserve-backed funding$7 below
bundled
customers
$14 above
bundled
customers
5 4¢/kWh
(27%)
$119M Full ORF + All
available reserve-backed funding +
Clean energy
procurement
reduction
$9 below
bundled
customers
$12 above
bundled
customers
All options would allow MCE to maintain compliance with MCE’s reserve and liquidity policies. The resulting revenue reduction or under-recovery of costs would be addressed through a combination of the Operating Reserve Fund (ORF, also referred to as the “Rate Stabilization Fund”), and other reserve-backed funding, and potentially a reduction in clean energy procurement.

Background:

MCE reviews potential rate adjustments each year in alignment with its fiscal year (April 1–March 31).

Although this review is conducted annually, rate changes are implemented only when needed.

Aligning the review with the fiscal year helps maintain consistency between the agency’s budget and its revenue requirements. Off-cycle adjustments may be made when necessary to ensure full cost recovery.

MCE’s rate design is guided by the following objectives:
• Revenue sufficiency: rates should recover all expenses, debt service and other expenditure requirements, and build prudent reserves, i.e., the “revenue requirement”. • Rate competitiveness: rates should allow MCE to successfully compete in the marketplace to retain and attract customers.
• Rate stability: rate changes should be minimized to reduce customer bill impacts. • Customer understanding: rates should be simple, transparent, and easily understood by customers.
• Equity among customers: rate differences among customers should be justified by differences in usage characteristics and/or cost of service. • Efficiency and conservation: rates should encourage conservation and efficient use of electricity (e.g., off-peak vehicle charging or time-of-use load shifting).

These objectives can be in tension with one another. Revenue sufficiency cannot be compromised, but the Board has discretion in balancing the remaining objectives.

MCE maintains strong financial stability through:
• Reserves equal to 60% of annual energy and operating expenses. • Liquidity of 240 days cash on hand.

FY 2025/26 projections show MCE exceeding both targets, with reserves expected at 109% and liquidity at 274 days.

The PG&E PCIA charges remain volatile. CCA customers face higher PCIA charges, while bundled PG&E customers receive credits. According to industry forecasts, PCIA costs are expected to converge across vintages beginning in 2027 and beyond.

Rate-Setting Process
The FY 2026/27 rate analysis incorporates updated load forecasts, customer participation assumptions, and projected procurement costs. Projected revenue at current rates is compared to the revenue requirement to determine whether adjustments are needed. Rates are then designed to recover each customer class’s allocated costs while balancing competitiveness and stability.

Rate Relief Tools
The following table summarizes the tools available to support rate competitiveness in FY 2026/27.

All amounts are estimates and subject to change as forecasts are updated.

Table 2. Potential Resources to Support Rate Competitiveness (FY 2026/27).

Tool Amount Description
Rate Reduction
Headroom
$89M Ability to reduce rates to align projected FY 2026/27 revenues with cost levels without creating a deficit
Operating Reserve
Fund
$70M Funds available currently for targeted rate relief Reserve-Backed
Funding
$24 to 36M Up to $36M available from reserves for rate relief with no impact on MCE’s reserve or liquidity targets
Reduced Clean Energy
Procurement
$0 to 17M Potential savings from lowering Renewable Portfolio Standards (RPS)/Carbon-Free (CF) procurement targets
Total Potential Rate
Relief
$183 to 212M Sum of all available tools for FY 2026/27
Clean Procurement Reduction Measures
California’s Renewables Portfolio Standard (RPS) requires:
• 60% renewable energy by 2030.
• 100% zero-carbon electricity by 2045.

Compliance is tracked through Renewable Energy Credits (RECs), which certify that one megawatt-hour of electricity was generated from a renewable resource, and these certificates are issued and managed in the Western Renewable Energy Generation Information System (WREGIS).

Compliance is enforced by the CPUC and the California Energy Commission (CEC), and annual procurement obligations are set within multi-year compliance periods (Compliance Period CP5:
2025–2027; CP6: 2028–2030).

MCE’s Current Clean Energy Goals
MCE’s Light Green service provides:
• 60% renewable energy (minimum achieved since 2017).
• 95% GHG-free energy (achieved since 2022).
1 1 MCE uses the CEC Power Content Label reported emissions factor (lbs of CO2e emitted per megawatt-hour) to calculate its carbon-free percentage equivalent. GHG intensity figures exclude biogenic CO2 and emissions from geothermal sources and grandfathered imports of firmed-and-shaped energy. For detailed MCE’s customer messaging for the Light Green product would need to be adjusted if the renewable and GHG-free content is reduced. MCE’s anticipated progress to increase renewable content to 85% by 2031 is shown in Table 3 below.

Table 3. State and MCE Light Green Targets. Summary of California State and MCE RPS and Carbon-Free (CF) Targets. 2025 2026 2027 2028 2029 2030
State RPS targets 47% 49% 52% 55% 57% 60%
MCE RPS Goals 60% 60% 65% 70% 75% 80%
State Carbon Free target 100% Carbon Free by 2045
MCE Carbon Free goals 95% 95% 95% 95% 95% 95%
Deep Green remains unaffected by any cost-saving adjustments.

Procurement Options Evaluated
Table 4. Cost Summary. Summary of the procurement options and the associated net changes to the cost of energy relative to current estimates. Scenario #1 represents no change to current targets.

Scenario #2 would delay increasing RPS content from 60% to 65% by one year. Scenarios #3-7 represent a departure from MCE’s Board policy towards an incrementally cleaner portfolio over time and would require changes to customer messaging, product descriptions, and materials. Reductions would likely create customer and community partner concern and confusion, and affect trust in MCE’s clean energy commitments.

FY 2026/27 FY 2027/28
Scenario
#
RPS/CF
%
Renewable
Content
Cost of Energy
(M)
Savings
(M)
Cost of Energy
(M)
Savings
(M)
1 60-65/95 60% $643 $0 $636 $0
2 60/95 60% $642 $0 $634 $2
3 60/70 60% $630 $13 $618 $18
4 RPS
Compliance/95
49-52%
(RPS
Compliance)
$640 $3 $632 $4
information about all GHG emissions from California's retail electricity suppliers, visit the CEC webpage.

Resource Adequacy (RA) is not reflected in the CEC Power Content Label, which reports only delivered retail energy and does not account for individual load serving entity RA contracts. RA is procured to meet CAISO reliability requirements and is not attributed to MCE’s retail energy portfolio for emissions reporting purposes. 5 RPS
Compliance/85
49-52%
(RPS
Compliance)
$634 $9 $625 $11
6 RPS
Compliance/70
49-52%
(RPS
Compliance)
$627 $16 $617 $19
7 RPS Banking/70
45%
(RPS
Banking)
$626 $17 $615 $21
RPS Compliance: Meet the state RPS requirements without banking any RECs.

RPS Banking: Bank excess 2025 RECs for use in 2026 and 2027 under CP5, which lowers the effective RPS to 45% for those years.

These measures could provide up to $17 million in cost savings in FY 2026/27 and $21 million in FY 2027/28.

FY 2026/27 Proposed Rate Options
MCE’s current residential E-TOU C generation rate is 14.62¢/kWh. This represents a weighted average rate that accounts for customer usage patterns as well as seasonal (summer/winter) and time-of-use (on-peak/off-peak) pricing.

Option 1: Generation Rate Reduction of 1.73¢/kWh (12%) — Full Cost Recovery • Achieves break-even and fully recovers projected costs. • Generation Rate: MCE 12.89¢/kWh vs. Bundled 12.57¢/kWh (0.32¢/kWh higher). • Gen + PCIA: MCE 16.55¢/kWh vs. Bundled 11.56¢/kWh (4.99¢/kWh higher). • Monthly Residential Bill Impact:
• Without PCIA: $1 below bundled.
• With PCIA: $22 above bundled.

Option 2: Generation Rate Reduction of 2¢/kWh (14%)
• Results in a $14M under-recovery of projected costs.
• Under-recovery addressed through the operating reserve fund. • Generation Rate: MCE 12.62¢/kWh vs. Bundled 12.57¢/kWh (0.05¢/kWh higher). • Gen + PCIA: MCE 16.28¢/kWh vs. Bundled 11.56¢/kWh (4.72¢/kWh higher). • Monthly Residential Bill Impact:
• Without PCIA: Equal to bundled.
• With PCIA: $21 above bundled.

Option 3: Generation Rate Reduction of 3¢/kWh (21%)
• Results in a $67M under-recovery of projected costs.
• Under-recovery addressed through the Operating Reserve Fund (ORF or “Rate Stabilization Fund”).
• Generation Rate: MCE 11.62¢/kWh vs. Bundled 12.57¢/kWh (0.95¢/kWh lower). • Gen + PCIA: MCE 15.28¢/kWh vs. Bundled 11.56¢/kWh (3.72¢/kWh higher). • Monthly Residential Bill Impact:
• Without PCIA: $4 below bundled.
• With PCIA: $17 above bundled.

Option 4: Generation Rate Reduction of 3.51¢/kWh (24%) — Uses All Available Reserves Without Falling Below Liquidity Targets
• Results in a $97M under-recovery of projected costs.
• Under-recovery addressed through the ORF; this option fully exhausts ORF and reserve-backed funding while maintaining liquidity targets. • Generation Rate: MCE 11.11¢/kWh vs. Bundled 12.57¢/kWh (1.46¢/kWh lower). • Gen + PCIA: MCE 14.77¢/kWh vs. Bundled 11.56¢/kWh (3.21¢/kWh higher). • Monthly Residential Bill Impact:
• Without PCIA: $7 below bundled.
• With PCIA: $14 above bundled.

Option 5: Generation Rate Reduction of 4¢/kWh (27%)
• Results in a $119M under-recovery of projected costs. • Under-recovery addressed through ORF, reserve-backed funding, and reduced clean energy procurement.
• Generation Rate: MCE 10.62¢/kWh vs. Bundled 12.57¢/kWh (1.95¢/kWh lower). • Gen + PCIA: MCE 14.28¢/kWh vs. Bundled 11.56¢/kWh (2.72¢/kWh higher). • Monthly Residential Bill Impact:
• Without PCIA: $9 below bundled.
• With PCIA: $12 above bundled.

Reserve & Liquidity Outlook
• All options maintain compliance with MCE’s reserve and liquidity policies. • Option 4 represents the break-even point for reserve sufficiency. • Projections assume stable customer participation and do not yet incorporate potential cost-saving measures.

Sustainability of Proposed Generation Rate Options
When evaluating the FY 2026/27 rate options, it is important to distinguish between the size of the rate reduction and the resulting generation rate level. Sustainability is determined by the generation rate level in each option, not by how large the reduction is.

Based on current forecasts, projected FY 2027/28 costs are slightly below the generation rate associated with Option 2. This means:
• Options 1 and 2
Both options set generation rate levels that are at or above projected FY 2027/28 costs, allowing them to be sustained next year without the need for a rate increase. • Options 3, 4, and 5
These options reduce the generation rate to levels that fall below what is needed to recover projected FY 2027/28 costs.
o Each option relies heavily on the ORF in FY 2026/27, leaving insufficient reserves to continue supporting these lower generation rates.
o As a result, the generation rate levels in Options 2–4 cannot be sustained into FY 2027/28.
o Under any of these options, the generation rate would need to increase next year to a level at or slightly below the Option 2 generation rate to achieve cost recovery.

In summary, while deeper reductions (Options 3–5) produce lower generation rates in the near term, those generation rate levels are not financially sustainable beyond FY 2026/27. Options 1 and 2 provide the only generation rate levels that can be maintained without requiring an upward adjustment next fiscal year.

Fiscal Impact:

None at this time. Fiscal impacts to be determined by future board action.

Recommendation:

Consider recommending a preferred rate reduction option to the full Board to assist with FY 2026/27 budget planning and finalization.

FY 2026/27 MCE Rate
Reduction Proposals
MCE Executive Committee
February 2, 2026
Meet the Presenter
2 Maíra Strauss
Chief Financial Officer and Treasurer
Maíra leads all MCE’s financial operations and strategies which include FP&A, Strategic Finance, Accounting and Risk Management. Her passion for sustainability is the driving force for her commitment to use MCE’s financial resources effectively to create maximum environmental impact.

Maíra brings over 15 years of experience in financial
management and strategic planning to her role. Prior to joining MCE, she consulted on strategic business practices for various international foundations and startups and
worked in the energy industry in Brazil. Maíra holds a
bachelor’s degree in business administration from SFSU and a post-baccalaureate certificate in business strategies from ESPM- RJ in Rio de Janeiro, Brazil.

Meet the Presenter
3 Kaladhar R. Bollampalli (Kal)
Director, Power Systems & Analytics
Kal joined MCE in June 2025 and leads the organization’s rates design, portfolio planning and analytics, and CAISO market operations.

Before joining MCE, Kal spent 16 years at Southern California Edison (SCE), where he managed energy portfolios valued at up to $2 billion and advanced market strategy, clean energy procurement, and portfolio optimization - efforts that delivered more than $150 million in customer savings over his tenure.

Prior to his work at SCE, Kal spent over 6 years as a software engineer, successfully implementing technology solutions in the energy and supply chain management sectors.

Kal holds a Bachelor of Engineering in Electronics and
Communications Engineering from OUCE and an MBA from
UCLA.

MCE Rate-Setting Principles
4 MCE Rate-Setting
Principles
Revenue
Sufficiency
Stability
Compete
Efficiency
Equity
Clarity
Recover all costs and maintain
required reserves
Minimize large or
frequent rate changes
Support MCE’s ability to
retain and attract
customers
Encourage conservation and smart
energy use (e.g., off-peak charging)
Rate differences should
reflect cost-of-service
differences
Simple, transparent, and
easy for customers to
understand
MCE’s Reserve & Liquidity Policy
5 • Maintain MCE's Reserves = 60% of
annual energy + operating
expenses
• Liquidity goal of 240 days cash on
hand (unrestricted cash &
investments / annual expenses)
• Ensure financial stability, rate stability
and strong credit rating
• FY 2025/26 Projection is based on current estimates and will be refined with updated financials
218
274
240
84%
109%
0%
25%
50%
75%
100%
125%
0 100
200
300
2024/25
Results
2025/26
Projection
Days of Cash on Hand
Reserves (% of Target)
Projected Days Liquidity on Hand Target Days Liquidity on Hand Reserves Actual (% of Target)
Historical (Generation + PCIA) Rate Comparison
6 • Rate comparisons use Residential E1/E-TOU-C plans and MCE’s 2017 PCIA vintage • PG&E generation and PCIA rates are set on a calendar year; MCE generation rates on a fiscal year (Apr–Mar) MCE’s Generation Rates + PCIA have generally been a lower-cost and stable option, with steady customer participation over time
77%
70%
79% 83% 82% 86% 86% 86% 87% 87% 87% 86% 87%

15.10 15.80
0%
25%
50%
75%
100%
125%
-

5.00 10.00

15.00 20.00

25.00 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Participation Rate (%)
¢/kWh
(Generation + PCIA) Rate Comparison
Participation Rate (%) PG&E (¢/kWh) MCE (¢/kWh)
FY 2026/27 MCE Rates Strategy
Balance Cost with Competitiveness and Long-Term Customer Retention 7 Reflect True Cost
• Align with reserve policy
• True cost = rate floor
• Supports long-term financial
stability
Competitiveness & Retention
Retention is influenced by more than price
• Competitive vs. PG&E
• Cleaner, greener power
• Historically stable & often lower rates
• Long-term value proposition (future years
may be lower)
Strategic implication: MCE must balance cost recovery with maintaining a compelling customer value proposition across price, sustainability, stability, and long-term certainty FY 2026/27 Rate Relief Tools
8 • All figures are estimates and subject to change as forecasts are updated Tool Amount Description
Rate Reduction Headroom $89M
Align FY 2026/27 revenues with costs without
creating a deficit
Operating Reserve Fund
(ORF) $70M Funds available currently for targeted rate relief Reserve-Backed Funding
(Reserves) $24 to 36M
Reserves available without affecting reserve/liquidity
targets
Reduced Clean Energy
Procurement $0 to 17M
Potential savings from lowering RPS/CF
procurement targets
Total Potential Rate Relief $183 to 212M Sum of all available tools for FY 2026/27 Potential Resources to Support Rate Competitiveness (FY 2026/27) Reduced Clean Energy Procurement Scenarios
9 FY 2026/27 FY 2027/28
Scenario
#
RPS/Carbon-Free (CF)
%
RPS CF
Cost of
Energy
($M)
Cost
Reduction
($M)
Cost of
Energy ($M)
Cost
Reduction
($M)
1 Status-Quo 60-65% 95% $643 $0 $636 $0
2 60/95 60% 95% $642 $0 $634 $2
3 60/70 60% 70% $630 $13 $618 $18
4 RPS Compliance/95 49-52% 95% $640 $3 $632 $4
5 RPS Compliance/85 49-52% 85% $634 $9 $625 $11
6 RPS Compliance/70 49-52% 70% $627 $16 $617 $19
7 RPS Banking/70 45% 70% $626 $17 $615 $21
• State RPS goals (’25/’26/’27): 47% / 49% / 52%; MCE RPS goals (’25/’26/’27): 60% / 60% / 65%; MCE’s CF goal 95% • MCE calculates CF percentage based on the CEC Power Content Label (PCL) reported emissions factor (lbs CO₂e/MWh). Resource Adequacy is not reflected in the PCL and is not attributed to MCE’s retail energy portfolio for emissions reporting purposes. • RPS Compliance options do not include REC banking
• REC banking allows excess RPS in one year to be used in later years within the same Compliance Period (CP); CP5 is from 2025-2027 • All figures are estimates and subject to change
FY 2026/27 Proposed Gen Rate Reduction Options
10 Option Gen Rate
Reduction
Under-Recovery How Addressed Bill Impact
(w/o PCIA)
Bill Impact
(w/ PCIA)
1 1.73¢/kWh
(12%)
$0M N/A $1 above bundled
customers
$22 above
bundled
customers
2 2¢
(14%)
$14M Partial ORF $0 below $21 above
3 3¢
(21%)
$67M Almost full ORF $4 below $17 above
4 3.51¢
(24%)
$94M Full ORF + Reserve-backed
funding $7 below $14 above
5 4¢
(27%)
$119M
Full ORF + Reserve-backed
funding + Lower clean
energy procurement
$9 below $12 above
• Rate comparisons use Residential E-TOU-C plan and MCE’s 2017 PCIA vintage. Residential rates are shown for illustration; similar reductions apply across all customer classes
• Proposed rate reductions are approximate; actual impacts vary by rate class and time-of-use period. • Monthly bill impacts assume 438 kWh of typical residential usage. • All figures are estimates and subject to change.

17.29 12.57

14.62 14.62

12.89 12.62 11.62 11.11 10.62
-

5.00 10.00

15.00 20.00

MCE PG&E PG&E MCE
Current
Option 1 Option 2 Option 3 Option 4 Option 5
2025 2026
¢/kWh
PG&E Gen rate
MCE Gen rate
FY 2026/27 Proposed Generation Rate Options
11 • All rate comparisons use Residential E1/E-TOU-C plans and MCE’s 2017 PCIA vintage; Operating Reserve Fund (ORF); Clean Energy (CE) • All figures are estimates and subject to change
• Proposed rate reductions are approximate; actual impacts vary by rate class and time-of-use period

1.73¢ 2¢ 3¢ 3.51¢ 4¢
Option 1 2 3 4 5
Deficit $0M $14M $67M $94M $119M
Source ORF + Reserves +Lower CE

17.29 12.57 14.62 14.62 12.89 12.62 11.62 11.11 10.62

1.18 (2.20) (1.01)

3.66 3.66 3.66 3.66 3.66 3.66

15.80 15.10

11.56 18.28

16.55 16.28 15.28 14.77 14.28
(5.00)
-

5.00 10.00

15.00 20.00

25.00 MCE PG&E PG&E MCE
Current
Option 1 Option 2 Option 3 Option 4 Option 5
2025 2026
¢/kWh
PG&E Gen rate MCE Gen rate
PG&E's PCIA Gen + PCIA
FY 2026/27 Proposed Generation Rate Options +
PCIA
12 • All rate comparisons use Residential E1/E-TOU-C plans and MCE’s 2017 PCIA vintage; Operating Reserve Fund (ORF); Clean Energy (CE) • All figures are estimates and subject to change
• Proposed rate reductions are approximate; actual impacts vary by rate class and time-of-use period

11.56 Option 1 2 3 4 5
Higher 4.99¢ 4.72¢ 3.72¢ 3.21¢ 2.72¢
MCE Reserve & Liquidity Outlook
13 • Outlook is based on current estimates and will be refined with updated financials • The revenue projections are based on a stable customer participation rate 218
274 290 282 255 240 242
240
84%
109%
116% 116% 116%
110% 110%
0%
25%
50%
75%
100%
125%
0 100
200
300
400
2024/25
Results
2025/26
Projection
Option 1 Option 2 Option 3 Option 4 Option 5
Days of Cash on Hand
Reserves (% of Target)
Projected Days Liquidity on Hand Target Days Liquidity on Hand Reserves Actual (% of Target)

16.55 16.28

15.28 14.77

14.28 11.56
-

5.00 10.00

15.00 20.00
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 ¢/kWh
(Generation + PCIA) Rate Comparison
PG&E (¢/kWh) MCE (¢/kWh)
Option 1 Option 2
Option 3 Option 4
Option 5 PG&E Projected
Generation + PCIA Rate Projections
14 • Comparisons use Residential E1/E-TOU-C plans and MCE’s 2017 PCIA vintage • Future PG&E generation rates are assumed to remain at 2026 levels, while PCIA values for 2027 and beyond rely on industry projections Projections
2027+: PCIA
convergence across
all vintages
Option 2:

Cost-based rates
make MCE’s Gen +
PCIA lower than
PG&E’s projection
Options 1–2: Gen
Rate sustainable
without increases.

Options 3–5: rely on
reserves now, require
a Gen Rate jump
later.

Projections
Recommendation
15 Select a preferred generation rate reduction option to support FY 2026/27 budget planning
Option 1: Reduce rate by 1.73¢/kWh (12%):

Full cost recovery; Sustainable into FY 2027/28; No use of reserves.

Option 2: Reduce rate by 2¢/kWh (14%):

Sustained rates likely into FY 2027/28; Some use of reserves.

Option 3: Reduce rate by 3¢/kWh (21%)
Heavy use of reserves; Rate increase likely needed for FY 2027/28 Option 4: Reduce rate by 3.51¢/kWh (24%)
Utilizes all available reserves while maintaining liquidity targets Option 5: Reduce rate by 4¢/kWh (27%)
Requires reduced clean energy targets & associated changes to customer messaging mceCleanEnergy.org
[email protected]
Discussion
February 2, 2026
TO: MCE Executive Committee
FROM: Maira Strauss, Chief Financial Officer and Treasurer Efren Oxlaj, Manager of Finance
RE: Proposed Fiscal Year 2026/27 Budget Elements (Agenda Item #09) ATTACHMENT: Presentation Proposed FY 2026/27 Budget Elements Dear Executive Committee Members:

Summary:

This report provides a preliminary overview of the Proposed Budget elements of MCE’s Operating Fund, Program Development, Resiliency Virtual Power Plant, and Energy Efficiency Fund for Fiscal Year (FY) 2026/27. The figures provided include initial estimates for energy revenue, cost of energy, operating expenses, and non-operating revenues and expenses. Projected program expenses are also shown. These figures are intended to support early Board discussion. They will be refined and presented in greater detail in the upcoming Budget Workshop on February 11, 2026. Projections shown should be viewed as high-level directional estimates only. Refinement is expected as updated procurement forecasts, rate modeling, and departmental budgets are finalized.

Background:

MCE’s fiscal year runs from April 1st through March 31st. Before the beginning of every fiscal year, staff present budgets to the Executive Committee and Board of Directors for consideration. MCE currently has four funds. The Operating Fund Budget captures activities related to MCE's core functions including sales of electricity, cost of energy, operating expenses, non-operating revenues and expenses, and capital outlay. Staff work with internal subject matter experts and external technical consultants to prepare forecasts for energy revenue and cost of energy. Staff also work with department heads to forecast operating expenses. The Program Development Fund is funded by 50% of the Deep Green premium, grants, and additional transfers from the Operating Fund, subject to your Board’s approval. This fund allows MCE to run several transportation electrification programs that help customers adopt electric vehicles (EVs) and install charging stations at workplaces and multifamily residences. Other electrification programs are also supported by this fund. The Resiliency Virtual Power Plant Fund focuses on scaling MCE’s virtual power plant efforts and customer energy storage. This fund may also include grants and Board approved transfers from the Operating Fund. Lastly, the Energy Efficiency Budget is entirely funded by the California Public Utilities Commission for energy efficiency programs.

A key decision for FY 2026/27 will involve selecting among five rate options, each with implications for energy revenue, cost of energy, and withdrawals from MCE’s Operating Reserve Fund (ORF) which currently holds $70 million in deferred income. Under the options being presented, the projected budget for operating, non-operating revenues, and program expenses remains the same.

However, the change in net position for the fiscal year will depend on which scenario your Board selects, as each reflects different revenue assumptions and energy cost projections. For further analysis and impact on customer bills for the options being presented, please see the staff report for Agenda Item #08.

Energy Revenue, Net
Energy revenue captures income generated from sales of electricity to customers. Electricity consumption is forecasted based on MCE’s customer accounts, incorporating historical usage, weather patterns and applicable rates. Actual revenue may vary depending on future weather conditions, customer behavior, and broader economic trends. For FY 2026/27, load forecasts have been adjusted downward to align with the mild summer weather observed during the last two summers in MCE’s service area.

For FY 2026/27, energy revenue will vary based on the rate scenario selected by your Board. All figures presented are net of uncollectible amounts, which are forecasted at 1.2% of sales based on customer payment data, and assume stable customer participation.

Status Quo: $772,440,000 (5.1% decrease from FY 2025/26 Approved Budget1 )
Under the status quo, MCE would maintain its current rate structure for the coming fiscal year.

Energy revenue would decline by $41.2 million year over year compared with the current Approved Budget. The decline reflects the downward adjustment to load forecasts mentioned above. This would generate sufficient energy revenue to pay for the cost of energy and other expenses. No withdrawals from the Operating Reserve Fund (ORF) would be required to generate a positive change in net position.

Rate Option 1: $683,373,000 (16.0% decrease from FY 2025/26 Approved Budget) Under Option 1, MCE would reduce its generation rate by 1.73¢/kWh or 12%. Energy revenue would decline by $130.3 million year over year compared with the current Approved Budget. Revenue would be set equal to MCE’s projected total expenses to achieve a break-even change in net position. No withdrawal from the ORF would be needed. 1 The FY 2025/26 Approved Budget includes a $13 million ORF withdrawal. The year over year percent change is calculated on the amount before the ORF withdrawal to highlight the revenue shortfalls tied to the rate options.

Rate Option 2: $668,919,000 (17.8% decrease from FY 2025/26 Approved Budget) Under Option 2, MCE would reduce its generation rate by 2¢/kWh or 14%. Energy revenue would decline by $144.8 million year over year compared with the current Approved Budget.

A withdrawal of $14.5 million from the ORF would be required to generate a break-even change in net position. Absent the ORF withdrawal, MCE’s net position would show a loss of $14.5 million.

Rate Option 3: $616,464,000 (24.2% decrease from FY 2025/26 Approved Budget) Under Option 3, MCE would reduce its generation rate by 3¢/kWh or 21%. Energy revenue would decline by $197.2 million year over year compared with the current Approved Budget.

A withdrawal of $66.9 million from the ORF would be required to generate a break-even change in net position. Absent the ORF withdrawal, MCE’s net position would show a loss of $66.9 million.

Rate Option 4: $588,957,000 (27.6% decrease from FY 2025/26 Approved Budget) Under Option 4, MCE would reduce its generation rate by 3.51¢/kWh or 24%. Energy revenue would decline by $224.7 million year over year compared with the current Approved Budget. A withdrawal of $70 million from the ORF would be required. Despite the withdrawal, the change in net position would show a loss of $24.4 million as the transfer would be insufficient to cover all the costs.

Rate Option 5: $564,009,000 (30.7% decrease from FY 2025/26 Approved Budget) Under option 5, MCE would reduce its generation rate by 4¢/kWh or 27%. Energy revenue would decline by $249.7 million year over year compared with the current Approved Budget.

A withdrawal of $70 million from the ORF would be required. Despite the withdrawal, the change in net position would show a loss of $32.4 million as the transfer would be insufficient to cover all the costs.

Table 1: Summary of Proposed Energy Revenue and year over year change.

Operating Reserve Fund
Options 2 through 5 would require withdrawals from the ORF, also known as the Rate Stabilization Fund. Your Board approved contributions of deferred revenue into the fund in previous years in accordance with Policy 16. The ORF currently holds $70 million of deferred FY 2025/26
Approved
FY 2026/27
Proposed Variance $ Variance %
Status Quo $ 813,689,500 $ 772,440,000 $ (41,249,500) (5.1%) Option 1 813,689,500 683,373,000 (130,316,500) (16.0%)
Option 2 813,689,500 668,919,000 (144,770,500) (17.8%)
Option 3 813,689,500 616,464,000 (197,225,500) (24.2%)
Option 4 813,689,500 588,957,000 (224,732,500) (27.6%)
Option 5 813,689,500 564,009,000 (249,680,500) (30.7%)
income2
. This is income that MCE did not recognize in previous fiscal years and can recognize in future fiscal years where net revenues are projected to be negative. By drawing on deferred revenue in years with lower energy margins, such as the upcoming fiscal year, MCE can maintain rate stability and mitigate abrupt changes in relative cost competitiveness resulting from PG&E rate changes.

Table 2: Summary of Proposed Energy Revenue with ORF withdrawals.

Cost of Energy
The cost of energy represents the largest expense for MCE. This category includes costs for portfolio content category 1 (PCC1) renewable energy, market hedges, and carbon-free energy from large hydroelectric or asset-controlling suppliers. Resource adequacy and net CAISO costs are also included. Energy costs fluctuate based on market conditions, including CAISO electricity prices, hydro availability, renewable generation output, and congestion in CAISO markets. These factors can materially increase or decrease MCE’s procurement costs from year to year.

The cost of energy will vary depending on whether your Board selects Rate Option 5. As shown on the Staff Report for Agenda Item #08, your Board has options that could be utilized to reduce the cost of energy by up to $17 million.

Status Quo: $631,944,000 (17.5% decrease from FY 2025/26 Approved Budget) Under the status quo, the cost of energy is projected to decline year over year. This decrease is driven primarily by lower forward prices for renewable energy, resource adequacy, and hedge contracts. MCE procures a decreasing share of its energy needs through forward contracts over time, which means that as older, higher-priced contracts expire, new procurement is occurring at more favorable market prices. As a result, the average cost of energy is trending downward. This reflects a reversal of the conditions experienced in the current fiscal year when rising market prices contributed to increase in MCE’s cost of energy. 2 Although the ORF balance is recorded as deferred income on MCE’s financial statements, this is strictly an accounting treatment. The underlying $70 million is actual cash that MCE already collected in prior years.

These funds remain available for liquidity needs and can be invested in accordance with MCE’s investment policy.

Energy Revenue ORF
Withdrawal Total
FY 2025/26 $ 813,689,500 $ 13,000,000 $ 826,689,500
Status Quo - 772,440,000 772,440,000
Option 1 - 683,373,000 683,373,000
Option 2 668,919,000 14,454,000 683,373,000
Option 3 616,464,000 66,909,000 683,373,000
Option 4 588,957,000 70,000,000 658,957,000
Option 5 564,009,000 70,000,000 634,009,000
Table 3: Cost of energy breakdown.

A breakdown of the energy contracts category will be provided at the upcoming Budget Workshop on February 11, 2026.

Options 1 through 4 assume the same cost of energy under the status quo.

Rate Option 5: $614,000,000 (19.7% decrease from FY 2025/26 Approved Budget) Under Option 5, MCE would need to reduce the cost of energy by $17 million to mitigate the impact of the revenue drop caused by the 4¢/kWh generation rate reduction. However, even after cost reductions and withdrawal from the ORF, MCE’s change in net position would show a loss of $32.4 million.

Operating Expenses: $55,586,000 (10.6% increase from FY 2025/26 Approved Budget) Operating expenses encompass a broad set of activities that support MCE’s core operations. This includes:
• Data manager costs for billing and customer data management. • Technical and Scheduling consultants for CAISO market participation and load forecasting. • PG&E service fees for customer data processing and billing coordination. • Legal and policy services from external providers.
• Communication services, including marketing and community engagement. • Other professional services ranging from accounting to consultants developing MCE’s CRM and data analytics infrastructure.
• General and Administrative including software costs, recruitment, and industry memberships. • Occupancy costs for MCE’s offices.
• Personnel costs such as wages, taxes, and benefits.
• A contingency allocation to address unforeseen expenses across these categories.

The proposed budget for operating expenses is rising in several key areas. • Data management costs for billing are increasing due to higher than anticipated accounts served following the enrollment of the City of Hercules and high general customer retention rates.

Cost of Energy
FY 2025/26
Approved Budget
FY 2026/27
Proposed Budget Variance $ Variance %
Energy Contracts $ 534,745,000 $ 438,275,000 (96,470,000)$ (18.0%) Resource Adequacy 145,713,000 105,565,000 (40,148,000) (27.6%) Net CAISO Costs 85,084,000 88,104,000 3,020,000 3.5%
Total 765,542,000 631,944,000 (133,598,000) (17.5%)
• Technical and scheduling consultant costs are growing because MCE is potentially transitioning to a new scheduling services provider, resulting in temporary vendor overlap and one-time transition expenses.
• PG&E service fees are increasing as the per-account charge has risen from 35 to 42 cents, and FY 2026/27 will reflect the first full year of this higher rate. • General and administrative expenses are also increasing, driven by higher software and data platform costs. The proposed increase also brings the budget for recruitment-related expenses in line with actual costs being incurred.
• Personnel costs are increasing due to the full year impact of vacant positions that were filled late in the current fiscal year amidst increasing workload in many staff departments. Similarly, the coming fiscal year will see the full year impact of the cost of living and health benefit adjustments made in this fiscal year. Four new positions are also needed to balance the increased workload being experienced by staff.

Non-Operating Revenues Net: $13,457,000 (8.9% decrease from FY 20225/26 Approved Budget) Non-operating revenues, net is the difference between non-operating revenues and non-operating expenses. Nonoperating revenues include interest and investment income from MCE’s cash and fixed income portfolio. Staff is conservatively assuming an average annual yield of 2.5% on the beginning balance of MCE’s holdings. Nonoperating expenses include bank fees associated with MCE’s credit facility.

Program Development Fund: $6,926,000 (10.8% increase from FY 2025/26 Approved Budget) The Program Development Fund Budget focuses on transportation electrification programs and other electrification efforts. It is financed by a transfer from the Operating Budget equal to 50% of the 1.25¢/kWh Deep Green premium plus additional amounts approved by your Board. In addition to the transfer, the fund may contain grant funding from external grantors.

The proposed spend for FY 2026/27 is $6.9 million, of which $5.9 million would be allocated to EV-related programs. This allocation would allow MCE to increase the rebate amount for Level 1 charging outlets and increase implementer budgets to provide greater customer project support.

The proposed budget would also allow MCE to provide over 870 rebates for purchasing an EV to income qualified customers.

Resiliency Virtual Power Plant (VPP) Fund: $2,374,000 (18.9% decrease from FY 2025/26 Approved Budget)
Your Board approved the creation of the Resiliency VPP Fund in 2019 in response to power outages which significantly impact the safety, health, and welfare of MCE’s customers, especially our vulnerable populations. Since then, the fund has expanded its scope to help scale MCE’s virtual power plants efforts. Like the Program Development Fund, this fund is financed by a transfer from the Operating Fund. Your Board has approved and transferred $9 million from the Operating Fund since its inception. In addition to the transfer, the fund may contain grant funding from external grantors.

The budget would also support incentives for installing heat pump water heaters and other electrification efforts.

The proposed budget would allow MCE to meet the $1 million match requirement under the VPP Flex grant from the California Energy Commission (CEC). It would also allow MCE to allocate $927 thousand to the MCE Sync program which helps customers shift their EV charging from peak hours and encourages charging during solar daytime hours through MCE’s proprietary app. The budget would also support MCE’s energy storage program, VPP pilot, and other grant match requirements.

Change in Net Position
The change in net position is the bottom line and reflects all revenues minus all expenses. The change in net position will vary subject to the rate option your Board selects.

Under the status quo MCE’s change in net position would show a gain of $89 million.

Status Quo
Energy Revenue, Net 772,440,000$
ORF Withdrawal 0
Cost of Energy (631,944,000)
Operating Expenses (55,586,000)
Non-Operating Revenues, Net 13,457,000
Program Expenses (9,300,000)
Consolidated Change in Net Position 89,067,000
Assumptions:

ORF Withdrawals 0
Cost of Energy Reduction 0
Under Option 1, MCE’s change in net position would be $0 (breakeven). Revenues would be set equal to costs.

Under Option 2, MCE’s change in net position would be $0 (breakeven) by withdrawing $14.5 million from the ORF.

Option 1
Energy Revenue, Net $ 683,373,000
ORF Withdrawal 0
Cost of Energy (631,944,000)
Operating Expenses (55,586,000)
Non-Operating Revenues, Net 13,457,000
Program Expenses (9,300,000)
Consolidated Change in Net Position 0
Assumptions:

ORF Withdrawals 0
Cost of Energy Reduction 0
Option 2
Energy Revenue, Net 668,919,000$
ORF Withdrawal 14,454,000
Cost of Energy (631,944,000)
Operating Expenses (55,586,000)
Non-Operating Revenues, Net 13,457,000
Program Expenses (9,300,000)
Consolidated Change in Net Position 0
Assumptions:

ORF Withdrawals 14,454,000
Cost of Energy Reduction 0
Under Option 3, MCE’s change in net position would be $0 (breakeven) by withdrawing $66.9 million from the ORF.

Under Option 4, MCE’s change in net position would show a loss of $24.4 million even after withdrawing $70 million from the ORF.

Option 3
Energy Revenue, Net $ 616,464,000
ORF Withdrawal 66,909,000
Cost of Energy (631,944,000)
Operating Expenses (55,586,000)
Non-Operating Revenues, Net 13,457,000
Program Expenses (9,300,000)
Consolidated Change in Net Position 0
Assumptions:

ORF Withdrawals 66,909,000
Cost of Energy Reduction 0
Option 4
Energy Revenue, Net $ 588,957,000
ORF Withdrawal 70,000,000
Cost of Energy (631,944,000)
Operating Expenses (55,586,000)
Non-Operating Revenues, Net 13,457,000
Program Expenses (9,300,000)
Consolidated Change in Net Position (24,416,000)
Assumptions:

ORF Withdrawals 70,000,000
Cost of Energy Reduction 0
Under Option 5, MCE’s change in net position would show a loss of $32.4 million even after withdrawing $70 million from the ORF and reducing cost of energy by $17 million.

Although MCE would experience a negative change in net position in Option 4 and 5, the agency would still meet its reserve and liquidity targets as shown below.

Reserves and Liquidity
MCE’s reserve target is to have 60% of expected cost of energy and operating expenses. Reserves are accounted for as the Net Position in MCE’s financial statements. The reserve goals are satisfied under each of the proposed options outlined above.

Option 5
Energy Revenue, Net $ 564,009,000
ORF Withdrawal 70,000,000
Cost of Energy (614,944,000)
Operating Expenses (55,586,000)
Non-Operating Revenues, Net 13,457,000
Program Expenses (9,300,000)
Consolidated Change in Net Position (32,364,000)
Assumptions:

ORF Withdrawals 70,000,000
Cost of Energy Reduction 17,000,000
84%
109%
137%
116% 116% 116% 110% 110%
0%
20%
40%
60%
80%
100%
120%
140%
$0
$150
$300
$450
$600
FY 2024/25
Audited
Results
FY
2025/2026
Projection
FY
2026/2027
Proposed -
Status Quo
FY
2026/2027
Proposed -
Option 1
FY
2026/2027
Proposed -
Option 2
FY
2026/2027
Proposed -
Option 3
FY
2026/2027
Proposed -
Option 4
FY
2026/2027
Proposed -
Option 5
Millions $
Target vs Projected
Reserves Goal
Reserve Target $ Actual Reserves $ Reserves Actual (% of Target) From a liquidity3 perspective, MCE would have sufficient cash to run the operations and no external funding sources would be required even under Options 4 and 5, which would generate a negative change in net position. Reserves were intentionally built to provide financial stability during periods of volatility and timing related impacts.

Like reserve goals, MCE would meet its liquidity target of 240 days on hand under each of the proposed options outlined above.

Fiscal Impacts:

None at this time.

Recommendation:

Discussion only.
3 Days cash on hand is based on unrestricted cash and investments x 365/ (operating expenses + cost of energy, each for the current fiscal year). Projections are based on the forecasted net position. 218
274
337
290 282 255 240 242
0 75
150
225
300
$0
$150
$300
$450
$600
FY 2024/25
Audited
Results
FY
2025/2026
Projection
FY
2026/2027
Proposed -
Status Quo
FY
2026/2027
Proposed -
Option 1
FY
2026/2027
Proposed -
Option 2
FY
2026/2027
Proposed -
Option 3
FY
2026/2027
Proposed -
Option 4
FY
2026/2027
Proposed -
Option 5
Days
Millions $
Target vs Projected
Liquidity Goal
Liquidity Target $ Total Projected Liquidity $ Projected Days Liquidity on Hand Proposed Fiscal
Year 2026/27
Budget Elements
MCE Executive Committee
February 2, 2026
Meet the Presenter
2 Maíra Strauss
Chief Financial Officer and Treasurer
Maíra leads all of MCE’s financial operations and strategies, which include FP&A, Strategic Finance, Accounting and Risk Management.

Meet the Presenter
3 Efren Oxlaj
Manager of Finance
Efren has been with MCE since 2019. He is responsible for financial planning, modeling, reporting and general
financial operations. He played a key role in the issuance of more than $2.5 billion in prepay bonds and currently
represents MCE on the California Community Choice
Financing Authority Working Group.

Efren holds a BS in Economics from Santa Clara University and is currently enrolled in its MS in Finance & Analytics program.

Context for FY 2026/27 Budget Setting
Current Situation (2026)
Bundled Gen + PCIA temporarily < MCE Gen
Rate + PCIA
• Increase driven by PCIA reforms and
improper retroactive ratemaking; CalCCA has
filed an appeal
• This is an anomaly, not a true cost trend
MCE Position
• Lower current power costs  rate-reduction
headroom
• Staff has developed rate-reduction options
4 Looking Ahead (2027+)
• PCIA values expected to converge, eliminating
the temporary distortion
• MCE’s cost-of-service-based rates are
projected to be below PG&E’s

13.92 13.56 13.62

13.80 14.37 14.32
10 15
20 2027 2028 2029
¢/kWh
(Generation + PCIA) Rate Comparison
MCE Cost-based PG&E Projected
• Based on Residential E-TOU-C and MCE’s 2017 PCIA vintage • Future PG&E generation rates are assumed to remain at 2026 levels, while PCIA values for 2027 and beyond rely on California electricity market projections Context for FY 2026/27 Budget Setting
• The budget for FY 2026/27 will be shaped by the rate reduction option your Board selects • Option 1 - reduce rates by 1.73¢/kWh or 12%
• Option 2 – reduce rates by 2¢/kWh or 14%
• Option 3 – reduce rates by 3¢/kWh or 21%
• Option 4 – reduce rates by 3.51¢/kWh or 24%
• Option 5 – reduce rates by 4¢/kWh or 27%
• Options 2 and 3 would create a deficit, which could be covered by withdrawing from the Operating Reserve Fund (ORF)
• Options 4 and 5 would create a deficit despite ORF withdrawals and reductions in the cost of energy
• The ORF has $70 million in deferred income
• Reserve and Liquidity goals are met across all options • Numbers presented are preliminary estimates and subject to change 5 Endurable (cost-based)
Rate increase likely for FY 2027/28
$827
$772
$683 $683 $683 $659 $634
(5.1%)
(16.0%)
(17.8%)
(24.2%) (27.6%)
(30.7%)
(35.0%)
(30.0%)
(25.0%)
(20.0%)
(15.0%)
(10.0%)
(5.0%)

0.0%
$500
$600
$700
$800
FY 2025/26 Status Quo Option 1 Option 2 Option 3 Option 4 Option 5 Millions
FY 2026/27 Proposed Energy Revenue
Energy Revenue, net ORF Withdrawal
% shows YoY decrease for Energy Revenue, net
Energy Revenue
6 • Load forecasts have been
adjusted downward to align with
the mild summer weather
observed over the last two years
• Figures are shown net of
uncollectibles
• Option 2 would require a $14 ORF
million withdrawal
• Option 3 would require a $67 ORF
million withdrawal
• Option 4 and 5 would require a
$70 million ORF withdrawal
• This would bring the ORF
balance to $0
Energy Revenue, net ORF Withdrawal Total
FY 2025/26 $ 813,689,500 $ 13,000,000 $ 826,689,500
Status Quo 772,440,000 - 772,440,000
Option 1 683,373,000 - 683,373,000
Option 2 668,919,000 14,454,000 683,373,000
Option 3 616,464,000 66,909,000 683,373,000
Option 4 588,957,000 70,000,000 658,957,000
Option 5 564,009,000 70,000,000 634,009,000
Cost of Energy
7 $766
$632 $632 $632 $632 $632 $615
500
550
600
650
700
750
FY 2025/26 Status Quo Option 1 Option 2 Option 3 Option 4 Option 5 Millions
FY 2026/27 Proposed Cost of Energy
Cost of Energy Cost Reduction
• Options 1 through 4 would preserve the
status quo
• Option 5 would require a reduction of $17
million
• YoY decrease driven by lower forward prices
for renewable energy, resource adequacy,
and hedge contracts
Cost of Energy
FY 2025/26
Approved
FY 2026/27
Proposed Variance $ Variance %
Status Quo $ 765,542,000 $ 631,944,000 $ (133,598,000) (17.5%) Option 1 765,542,000 631,944,000 (133,598,000) (17.5%)
Option 2 765,542,000 631,944,000 (133,598,000) (17.5%)
Option 3 765,542,000 631,944,000 (133,598,000) (17.5%)
Option 4 765,542,000 631,944,000 (133,598,000) (17.5%)
Option 5 765,542,000 614,944,000 (150,598,000) (19.7%)
Operating Expenses
8 FY 2025/26
Approved
FY 2026/27
Proposed Variance $ Variance %
$ 50,249,000 $ 55,586,000 $ 5,337,000 10.6%
Data Management:
• Increased billing activity after City of Hercules enrollment Technical & Scheduling Consultants:
• Transition to new scheduling services provider
• Temporary vendor overlap + one-time transition costs
PG&E Service Fees:
• Per-account charge rising from $0.35 → $0.42
• FY 2026/27 reflects first full year at new rate
General & Administrative:
• Higher software and data platform costs
• Recruitment budget aligned with actual spending
Personnel:
• Full year impact of vacant positions that were filled late in the current fiscal
• Full year impact of the cost of living and health benefit adjustments made in this fiscal year
• New positions are also needed to balance the increased workload being experienced by staff
Non-operating Revenue, Net
9 FY 2025/26
Approved
FY 2026/27
Proposed Variance $ Variance %
$ 14,775,000 $ 13,457,000 $ (1,318,000) (8.9%)
• Non-operating revenues, net = non-operating
revenues minus non-operating expenses
• Non-operating revenues come from interest and
investment earnings on MCE’s cash and fixed-income
portfolio
• Budget assumes a conservative 2.5% annual yield on
MCE’s holdings
• Non-operating expenses consist primarily of bank fees tied to MCE’s credit facility
Program Expenses
10 Program Development Fund
Proposed budget: $6.9 million
• Most of the budget would be allocated towards EV
related programs (incentives for charging stations and
purchases for income qualified customers)
Resiliency Virtual Power Plant (VPP) Fund
Proposed budget: $2.4 million
• Would support MCE’s energy storage program, VPP,
and additional grant match commitments
FY 2025/26
Approved
FY 2026/27
Proposed Variance $ Variance %
$ 9,181,000 $ 9,300,000 $ 119,000 1.3%
Change in Net Position
11 The agency has sufficient cash to run the operations and no external funding sources would be required, even under options 4 and 5.

Status Quo Option 1 Option 2 Option 3 Option 4 Option 5 Energy Revenue, Net $ 772,440,000 $ 683,373,000 $ 668,919,000 $616,464,000 $588,957,000 $564,009,000 ORF Withdrawal 0 0 14,454,000 66,909,000 70,000,000 70,000,000 Cost of Energy (631,944,000) (631,944,000) (631,944,000) (631,944,000) (631,944,000) (614,944,000) Operating Expenses (55,586,000) (55,586,000) (55,586,000) (55,586,000) (55,586,000) (55,586,000) Non-Operating Revenues, Net 13,457,000 13,457,000 13,457,000 13,457,000 13,457,000 13,457,000 Program Expenses (9,300,000) (9,300,000) (9,300,000) (9,300,000) (9,300,000) (9,300,000) Consolidated Change in Net Position 89,067,000 0 0 0 (24,416,000) (32,364,000) Assumptions:

ORF Withdrawals 0 0 14,454,000 66,909,000 70,000,000 70,000,000 Cost of Energy Reduction 0 0 0 0 0 17,000,000
Progress towards
Reserves and
Liquidity Goals
Reserves
13 84%
109%
137%
116% 116% 116% 110% 110%
0%
20%
40%
60%
80%
100%
120%
140%
$0
$150
$300
$450
$600
FY 2024/25
Audited Results
FY 2025/2026
Projection
FY 2026/2027
Proposed -
Status Quo
FY 2026/2027
Proposed -
Option 1
FY 2026/2027
Proposed -
Option 2
FY 2026/2027
Proposed -
Option 3
FY 2026/2027
Proposed -
Option 4
FY 2026/2027
Proposed -
Option 5
Millions $
Target vs Projected
Reserves Goal
Reserve Target $ Actual Reserves $ Reserves Actual (% of Target) • Reserves target is met across all options.
• Numbers are inclusive of cost of energy reductions and withdrawals from the ORF Liquidity
14 218
274
337
290 282
255 240 242
0 75
150
225
300
$0
$150
$300
$450
$600
FY 2024/25
Audited Results
FY 2025/2026
Projection
FY 2026/2027
Proposed -
Status Quo
FY 2026/2027
Proposed -
Option 1
FY 2026/2027
Proposed -
Option 2
FY 2026/2027
Proposed -
Option 3
FY 2026/2027
Proposed -
Option 4
FY 2026/2027
Proposed -
Option 5
Millions $
Days
Target vs Projected
Liquidity Goal
Liquidity Target $ Total Projected Liquidity $ Projected Days Liquidity on Hand • Liquidity target is met across all options.
• Numbers are inclusive of cost of energy reductions and withdrawals from the ORF Thank you!
mceCleanEnergy.org
[email protected]

MCE Executive CommitteeFebruary 2, 2026

MCE Executive Committee
February 2, 2026