Regulatory Packet Part 3 — MCE Board of Directors, July 17, 2025 (part 1 of 2)

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue
Implementation and Administration, and Consider
Further Development, of California Renewables
Portfolio Standard Program.

Rulemaking 24-01-017
DRAFT 2025 RENEWABLES PORTFOLIO STANDARD PROCUREMENT PLAN OF

MARIN CLEAN ENERGY

PUBLIC VERSION
Sai Powar
Policy Analyst
Marin Clean Energy
1125 Tamalpais Avenue
San Rafael, CA 94901
(415) 464-6044
[email protected]
Dated: June 30, 2025
1 BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue
Implementation and Administration, and Consider
Further Development, of California Renewables
Portfolio Standard Program.

Rulemaking 24-01-017
DRAFT 2025 RENEWABLES PORTFOLIO STANDARD PROCUREMENT PLAN OF

MARIN CLEAN ENERGY

PUBLIC VERSION
In accordance with the California Public Utilities Commission’s (“Commission” or “CPUC”) April 17, 2025, Assigned Commissioner and Assigned Administrative Law Judges’ Ruling Identifying Issues and Schedule of Review for 2025 Renewables Portfolio Standard Procurement Plans (“ACR”), Marin Clean Energy (“MCE” or “Agency”), hereby submits this Draft 2025 Renewables Portfolio Standard Procurement Plan (“RPS Procurement Plan”). As directed by the ACR, this RPS Procurement Plan includes responses for the issues expressed in ACR sections 6.1-6.15.

MCE notes that certain issues and requests in these ACR sections apply to the other retail sellers (electrical corporations and electric service providers), and do not extend to Community Choice Aggregators (“CCAs”). MCE is nevertheless voluntarily responding to these ACR sections in the interest of transparency and in order to collaborate with the Commission. However, the submission of this RPS Procurement Plan pursuant to the ACR should not be construed as a waiver of the right to assert that components of Senate Bill (“SB”) 790 (2012) or that Commission decisions and rulings on RPS Procurement Plan submittals do not extend to CCAs. MCE reserves the right to challenge any such assertion of jurisdiction over these matters. 2 In reviewing this RPS Procurement Plan, MCE encourages the Commission to consider the differences between California’s investor-owned utilities (“IOUs”) and other retail sellers, including CCAs. Differing levels of detail, procedure, complexity, and coordination within the planning documents submitted by these organizations are appropriate.

I. Summary of Major Changes to RPS Plan
This Section describes the most significant changes between MCE’s Draft 2024 RPS Procurement Plan (which was deemed final by Decision 24-12-035) and its Draft 2025 RPS Procurement Plan. A redline of this Draft 2025 RPS Plan against MCE’s Draft 2024 RPS Plan is included as Appendix A. The table below provides a list of key differences between MCE’s 2024 and 2025 RPS Procurement Plans.

Table 1: Key Changes to MCE's RPS Procurement Plan
Plan Reference Plan Section Summary/Justification of
Change
2025 RPS Procurement Plan:

Section IV
Assessment of RPS Portfolio
Supplies and Demand Updated to provide latest
information on MCE’s
progress towards meeting the
requirements of Mid-Term
Reliability Decision, D.21-06-
035, D.23-02-040, and
potential RPS planning
implications.
2025 RPS Procurement Plan:

Section I.V.B.2
Curtailment Frequency,
Forecasting, Costs Updated information regarding
historical curtailments in
Calendar Year 2024 and
Calendar Year 2025 to date.
2025 RPS Procurement Plan:

Section V Project Development Status
Updates
Updated the project
development status template,
Appendix D, to reflect the
recent progress of renewable
3 generating projects that have
yet to achieve commercial
operation. Updated narrative
to describe projects, including
status of delays and contract
online dates.
2025 RPS Procurement Plan:

Section IV.C Portfolio Optimization Updated to reflect how MCE is optimizing existing
resources and future
procurement to meet new
CPUC reliability goals.
2025 RPS Procurement Plan:

Section VII
Risk Assessment Updated to include further
detail on how MCE evaluates
risk, especially in light of
Mid-Term Reliability
Decisions, D.21-06-035 and
D.23-02-040.
2025 RPS Procurement Plan:

Section VIII
Renewable Net Short
Calculation
Updated the Renewable Net
Short template, Appendix C,
to reflect actual data through
2024 and updated projections
through 2035.
2025 RPS Procurement Plan:

Section XIV
Cost Quantification Updated Cost Quantification
template, Appendix E, to
reflect updated cost
projections associated with
actual and planned RPS
procurement through 2034.

II. Executive Summary Key Issues
In this Draft 2025 RPS Procurement Plan, MCE provides information and updates regarding its progress in meeting applicable renewable energy planning and procurement targets, as well as additional detail in response to the expanded requirements set forth in the ACR. 4 MCE, California’s first CCA, is a not-for-profit public agency that began service in 2010 with a mission to confront the climate crisis by eliminating fossil free greenhouse gas emissions, producing renewable energy, and creating equitable community benefits. In 2024, MCE served approximately 585,000 customer accounts in 37 communities across Contra Costa, Marin, Napa, and Solano counties, with annual retail sales of approximately 5,500 gigawatt hours. In 2025, MCE expanded its service area to 38 communities with the inclusion of the City of Hercules. MCE offers its customers a 60% renewable default service (“Light Green”), as well as two 100% renewable energy service options (“Deep Green” and “Local Sol”).

MCE is governed by a Board of Directors (“Board”) comprised of 36 locally elected officials. The Board sets policy for the Agency and oversees its operations. Depending upon the issue, representatives from MCE’s governing Board and committees generally convene two to three times per month with advance public notice provided in compliance with the Brown Act.

MCE updates its biennial Integrated Resource Plan (“IRP”) mandated by SB 350 (2015).

The IRP submitted to the Commission biennially has been primarily oriented towards supporting California’s achievement of its 2030 Greenhouse Gas (“GHG”) reduction targets. MCE’s internal commitment to clean energy has resulted in a default supply portfolio that reached 60% renewable in 2017, thirteen years ahead of the statewide procurement mandate. MCE is also attentive to applicable long-term renewable energy contracting requirements and has secured 65% of its total projected 2025 RPS requirements (relative to California’s interim annual RPS procurement mandate) via numerous long-term contracts, exceeding pertinent long-term contracting requirement established by SB 350 (2015). MCE observes that it has also procured over 100% of its voluntary, internally adopted renewable energy need, which, in aggregate, approximates 76% of projected retail load. MCE is also fully compliant with all CPUC Resource Adequacy (“RA”) 5 requirements, to support the reliability needs of the state.

MCE maintains its clean, balanced portfolio by closely monitoring ongoing market conditions, including but not limited to curtailment, customer demand, and policy changes. MCE also monitors unanticipated market events, such as inflationary and supply chain pressures and their impacts on both the supply and demand sides of the market. In optimizing its portfolio, MCE prioritizes the maintenance of a balanced, diverse, and reliable portfolio; adhering to its commitment to clean energy and suppressing customer costs to the greatest practical extent.

MCE’s commitment to clean energy has led to the exploration of opportunities to mitigate the impacts of air pollution in regions of the state where communities have been disproportionately affected by the existing generating fleet, as well as the need to bring economic benefits to communities with high levels of poverty and unemployment. To address this concern, MCE continues to evaluate the procurement of “clean resource adequacy” (“Clean RA”) and the feasibility (both technological and economic) of transitioning to increased use of carbon-free capacity sources to meet statewide reserve capacity mandates.

MCE’s RPS Procurement Plan details its current solicitations and its bid review and selection processes. The Plan also describes how MCE applies the Least-Cost Best Fit concept to its portfolio to support its priorities as an agency created to provide clean energy, amongst other customer- and community-focused service offerings and programs.

MCE continues to closely monitor its exposure to a variety of risk factors, as discussed more fully below in Section VII. MCE continues to find that its thorough analysis of both portfolio-and project- level risks, combined with its significant margin of over-procurement relative to statewide RPS goals, renders a quantitative risk assessment model unnecessary at this time. This noted, MCE continues to assess the need for such a model and may employ additional analytical 6 tools in the future.

III. Compliance with Recent Legislation and Impact of Regulatory Changes This RPS Procurement Plan addresses the requirements of relevant legislation and the Commission’s regulatory framework and describes how this RPS Procurement Plan demonstrates that MCE meets these requirements.

SB 350 was signed by the Governor on October 7, 2015. SB 350 set a new RPS procurement target of 50% by December 31, 2030. On December 20, 2016, the Commission issued Decision (“D.”) 16-12-040, which partially implemented the increased targets of SB 350 by establishing new compliance periods and procurement quantity requirements. On July 5, 2017, the Commission issued D.17-06-026, which implemented some of the key remaining elements of SB 350, including adopting new minimum procurement requirements for long-term contracts and owned resources, as well as revising the excess procurement rules. As discussed in greater detail in Section IV.A.1, MCE projects that 96% of its total projected 2025 RPS procurement target will be met with long-term contracts; MCE further expects that nearly 87% of mandated RPS purchases related to Compliance Period 4 will be fulfilled via deliveries from long-term renewable energy contracts.

SB 100 was signed by the Governor on September 10, 2018, and became effective on January 1, 2019. SB 100 increased the RPS procurement requirements to 44% by December 31, 2024, 52% by December 31, 2027, and 60% by December 31, 2030. On June 6, 2018, the Commission issued D.18-05-026, which implemented changes made by SB 350 to the RPS waiver process and reaffirmed the existing RPS penalty scheme. In July 2018, the Commission instituted Rulemaking (“R.”) 18-07-003 to continue the implementation of the RPS program. On June 28, 2019, the Commission issued D.19-06-023, which continues to use a straight-line method to 7 calculate compliance period procurement quantity requirements. The current RPS procurement targets are incorporated in MCE’s Renewable Net Short (“RNS") Calculation Table as further described in Section VIII below and attached hereto as Appendix C. On a projected basis, MCE’s current RPS procurement is sufficient to exceed applicable, internally adopted renewable energy procurement targets through 2025, including the minimum margin of over-procurement based on MCE’s risk assessment, as further described in Sections VII and IX.

Additional RPS procurement efforts remain ongoing, and MCE intends to augment existing RPS contracts with additional supply to promote statutory compliance, as well as the achievement of internal RPS targets, in 2026 and beyond.

SB 901, signed by Governor Brown on September 21, 2018, added Public Utilities Code Section 8388, which requires any IOU, publicly owned electric utility, or CCA with a biomass contract meeting certain requirements to seek to amend the contract to extend the expiration date to be five years later than the expiration date that was operative as of 2018. MCE does not have a contract with a biomass facility that is covered by Public Utilities Code Section 8388.

In accordance with SB 255 (Bradford, 2019), D.22-04-035 revises the Commission’s Supplier Diversity Program set forth in General Order (“GO”) 156 to incorporate CCAs, Energy Service Providers (“ESPs”), and smaller utilities with certain revenue thresholds. MCE is committed to supporting sustained and fairly compensated local job opportunities through participation in the clean energy industry. To the extent allowed by state law, MCE seeks to create market incentives and partnerships to encourage diversity and a sustainable workforce through its support for:
● Fair compensation in direct hiring, renewable development projects, customer programs, internships, and procurement services;
8 ● Development of locally generated renewable energy within the MCE service area; ● Direct use of union members from multiple trades;
● Quality training, apprenticeship, and pre-apprenticeship programs; ● Direct use of businesses local to the MCE service area; ● Development of California-based job opportunities;
● Business and workforce initiatives located in low-income and disadvantaged communities;
● Direct use of Disabled Veteran-owned Business Enterprises and LGBT-owned Business Enterprises;
● Direct use of green and sustainable businesses; and
● Use of direct hiring practices that promote diversity in the workplace.

These commitments, made prior to the passage of SB 255, align with SB 255’s direction for CCAs to take steps to increase procurement from small, local, and diverse businesses in all procurement categories.

MCE has submitted annual supplier diversity reports to the CPUC since 2020, the first year SB 255 was in effect.1
These reports follow the same timeline and reporting structure that applies to the other entities that report to the CPUC annually under GO 156, adjusted to account for MCE’s status as a public agency subject to Proposition 209.2
MCE and other CCAs have been working
with the CPUC’s Supplier Diversity staff since the passage of SB 255 to ensure reporting 1 See https://mcecleanenergy.org/wp-content/uploads/2024/06/MCE_Supplier-Diversity-Report_FINAL.pdf for MCE’s 2024 Supplier Diversity report 2 Proposition 209 was approved by voters in 1996 and amended the California Constitution to prohibit the state, including local government agencies, from discriminating or granting preferential treatment on the basis of race, sex, color, ethnicity, or national origin in the operation of public employment, public education, and public contracting. 9 requirements for CCAs are appropriate and conform to SB 255, and will continue to do so on an ongoing basis, as set forth in D.22-04-035.

Assembly Bill (“AB”) 843 (Aguiar-Curry, 2021) authorizes CCAs to submit eligible bioenergy projects for cost recovery pursuant to the Bioenergy Market Adjusting Tariff (“BioMAT”) program. The BioMAT program is a feed-in tariff program for small bioenergy renewable generators less than 5 megawatts (“MW”) in size, offering 250 MW total to eligible projects through a fixed price standard contract to export electricity to California’s IOUs and CCAs. Electricity generated through the BioMAT program counts towards RPS targets. MCE engaged with the California Community Choice Association (“CalCCA”), the CPUC, and the IOUs to establish program implementation details to facilitate CCA participation in the program; however, MCE does not participate in this program currently. SB 1109 (Caballero, 2022) and AB 2750 (Gallagher, 2023) require entities, including CCAs, with a contract to procure electricity generated from biomass that expires or expired on or before December 31, 2028, to amend or establish a new contract that includes an expiration date five years later than the expiration date in the contract that was operative in 2022. MCE does not have any contracts that fit this requirement.

SB 1020 (Laird, 2022) sets interim targets for renewable and zero-carbon energy in California, requiring 90% of all retail sales of electricity be zero-carbon by December 31, 2035, and 95% of all retail sales of electricity be zero-carbon by December 31, 2040. MCE’s most recent Operational Integrated Resource Plan (“OIRP”) adopted interim targets that are more stringent than what is required for SB 1020,3
therefore, MCE expects to meet these goals. Additionally, 3MCE’s Light Green service option is expected to be 95% GHG-free by 2023 and is expected to reach 85% renewable energy by 2029.
https://www.mcecleanenergy.org/wp-content/uploads/2021/11/MCE-Operational-Integrated-Resource-Plan_2022.pdf.pdf. 10 MCE is working with state partners to understand the requirements of SB 1020 for other agencies and exploring how to support those other agencies in meeting SB 1020 goals. In the interim, MCE notes that state agency accounts may enroll in MCE’s 100% renewable energy service option, Deep Green, to immediately receive zero-carbon retail energy service.

AB 1373 (Garcia, 2023) authorizes the CPUC to request that the Department of Water Resources (“DWR”) act as a central procurement entity (“CPE”) to conduct procurement of certain eligible long lead-time resources (“LLT”) on behalf of customers of all LSEs under the CPUC’s IRP purview. On August 22, 2024, the CPUC issued D.24-08-064 making an initial need determination of up to 10.6 gigawatts (“GW”) of nameplate capacity of the following emerging technologies: offshore wind (up to 7.6 GW), enhanced geothermal systems (up to 1 GW), multi-day long duration energy storage (“LDES”) (up to 1 GW), and LDES with a discharge period of at least 12 hours (up to 1 GW). Using the most recent vintage of the demand forecast, CPUC will allocate CPE procurement benefits to LSEs and recover costs from all customers. DWR will tentatively begin development of solicitation plans and materials in 2025 and conduct pre-bid activities in early 2026 for LDES. MCE will continue to engage with the CPUC as the CPE mechanism is developed and incorporate the consideration of CPE resources, if procured, in its procurement strategy in future IRPs.

AB 1373 (Garcia, 2023) also requires the CPUC to include cost-effective resource diversity in its integrated resource planning processes. The bill permits CCAs to satisfy their portion of the CPUC’s resource diversity requirements so long as the CCA’s proposal promotes the efficient achievement of state energy policy objectives and does not result in incremental costs to bundled customers. The CPUC is currently in the process of developing a new IRP framework, the Reliable and Clean Power Procurement Program (“RCPPP”). In March 2025, the CPUC put forth its 11 proposal on RCPPP that included reliability procurement and GHG reduction target frameworks for stakeholder consideration MCE is engaging in R.20-05-003 and working with CalCCA to facilitate effective design of the new program and establish reasonable implementation details.

MCE will address requirements set forth in the RCPPP after the program’s adoption and tentative implementation in 2027.

AB 2368 (Petrie-Norris, 2024) requires the CPUC to ensure that the RA program can reasonably maintain a standard measure of reliability, such as a 1-in-10 loss of load expectation (“LOLE”) metric, and use it for planning purposes. The bill also adds midterm procurement, along with short term and long term, to IRP requirements. MCE will address these requirements as they are implemented by the CPUC.

IV. Assessment of RPS Portfolio Supplies and Demand
IV.A. Portfolio Supply and Demand
(i) Assessment of Portfolio Supply and Demand through 2035 MCE continues to project that it will meet or exceed applicable RPS procurement obligations over the long-term planning horizon (through 2035, which reflects the final year of the planning period addressed in this document). The exact characteristics of MCE’s renewable supply portfolio are expected to vary over the planning horizon based on a variety of considerations, including market developments and RPS product availability, policy changes, technological improvements, Agency preferences, and/or other factors.

Of note, due to apparent RPS supply constraints, which affected Portfolio Content Category 1 (“PCC1”)4
product availability and pricing in 2024 and 2025, MCE observes that 4 A resource which is either located within California, or directly delivers to California without substituting energy from another source.
12 PCC1 prices increased more than 400% during the 18-month period between November 2022 and June 2024. While the full scope of circumstances contributing to this pricing runup remains unclear, many retail sellers, including MCE, were subjected to substantial budgetary impacts in meeting adopted portfolio objectives. The unexpected rise in RPS prices and the associated changes in regional short-term renewable energy markets impact how MCE can balance customer affordability with achieving environmental objectives that generally exceed statewide mandates.

Figure 1: MCE’s PCC1 Renewable Price 2024-2026
13 This recent price volatility highlighted a relatively new, but significant, risk facing buyers of short-term renewable energy products which, for several years, had experienced relatively low levels of pricing variability. State procurement directives, including the mid-term reliability and supplemental mid-term reliability programs, have had the effect of multiple buyers entering the market at the same time due to the universally applicable schedule of compliance deadlines assigned through such processes. Additionally, recent tariff discussions have introduced the risk of substantive cost increases for certain projects. These factors have exerted upward pressure and considerable uncertainty on certain technology/project types, which may play meaningful roles in California meeting its eventual RPS goals – particularly in a way that balances affordability for ratepayers. MCE continues to assess the best approach for dealing with these risks which may be subject to considerable iteration. For example, taking on additional long-term contracts, which can often promote increased price stability within an RPS contract portfolio (even though overall costs associated with such contracts can be higher than prices identified in short-term markets) could mitigate exposure to the occasional volatility experienced in short-term RPS markets.

However, disproportionately high levels of long-term contracting could reduce planning flexibility, including a retail seller’s ability to take advantage of emerging technologies, adapt to policy changes, and react to periodic market fluctuations.

In the near term, MCE expects budgetary and rate-related impacts associated with addressing prior (2024 and 2025) and projected (2026 and 2027) RPS open positions, but MCE remains committed to fulfilling its internally adopted RPS targets as planned. Due to prudent planning, MCE is well resourced for the early stages of Compliance Period 5, so short-term RPS procurement efforts will be predominantly focused on outstanding needs in 2026 and 2027, years in which prices have recently subsided. Over the long-term planning horizon, MCE believes that 14 its disciplined and diversified approach to RPS procurement will lead to average portfolio costs that are manageable and considerate of customer rate sensitivities as well as statewide planning needs.

As previously noted, MCE’s internally adopted renewable energy procurement targets have been set in excess of state-imposed mandates, creating a natural compliance buffer. For example, approximately 74% of MCE’s aggregate supply portfolio was comprised of RPS-eligible renewable energy in 2024, an amount exceeding the state’s interim annual procurement mandate by nearly 68%. Similar to previous years, this significant level of over-procurement would have accommodated massive fluctuations in annual retail sales and/or anticipated renewable energy deliveries before triggering potential compliance risks for MCE. Given the significance of MCE’s internally established 60% renewable target (which persists through 2025 before increasing thereafter), past success exceeding applicable compliance mandates, existing supply commitments and ongoing planning/procurement efforts focused on RPS-eligible energy, MCE does not foresee any issues fulfilling future renewable supply commitments.

MCE continues to monitor the prospective impacts to its customer base associated with California’s direct access market due to SB 237 (2018) and D.19-05-043. Should there be material changes to direct access availability for non-residential accounts, or direct access is expanded in the future, MCE will accordingly reflect such an outcome in its planning process. With this in mind, MCE’s analysis shall remain ongoing and may result in future adjustments to MCE’s load forecast and related renewable energy procurement obligations, which would be expected to decrease if MCE load migrates to direct access providers.

Additionally, MCE is aware that supply chain impacts continue to exist, and for renewable energy projects that have yet to achieve commercial operation, MCE will closely monitor 15 progress in case such issues impact expected online dates. Federal policy changes regarding Tax Credits and imposition of significantly increased tariffs that could be applied to certain renewable and battery storage infrastructure is another important concern being monitored by MCE, as such risk is often being addressed by “price reopener” provisions inserted in various renewable energy contracts. These provisions not only create the potential for budgetary uncertainty but also the reality that extreme price increases may compromise the prospect of project completion (via contract termination), leaving the affected retail seller to search for project alternatives that may be necessary to backfill vacated supply. Regarding demand side impacts, these are often more challenging to isolate, as normal variations in usage caused by weather may obscure otherwise atypical variations in consumption. With current monetary policy focused on controlling inflation, MCE will be attentive to potential changes in customer usage that may result from ongoing policy adaptations, particularly those intended to control persistent inflationary pressures. Based on available data and related analyses conducted to date, impacts to MCE’s overall load and sales appear to be relatively modest.
(ii) Assessment of Need for RPS Resources with Specific Deliverability Characteristics
MCE regularly analyzes and assesses its renewable portfolio mix to identify supply, fit, and compliance needs. While compliance with the RPS program has not been an issue of concern, as California increases its renewable and carbon free targets, there is a need for MCE to continue diversifying its resource mix. Resources with diverse deliverability characteristics help in mitigating risk exposure to market forces while providing grid reliability. Peaking dispatchable resources, such as storage paired with solar or wind, are critical in meeting high demand periods in the future. However, this requires having baseload resources like geothermal to allow for the flexibility to dispatch marginal resources as load shifts. Reliance on intermittent 16 resources like solar and wind alone exposes one to congestion and potential curtailment risks.

This risk continues to grow with the accelerated adoption of solar and wind on the grid. MCE is aware of these factors and continues to pursue a diverse set of renewable resources to not only meet its RPS obligations but also maintain operational flexibility while contributing to overall system reliability.
(iii) Experience Managing Exposure to Negative Market Prices MCE closely monitors twelve separate locations that are indicative of renewable energy resources that are exposed to market prices and potential curtailment. Resources at those locations are bid into the CAISO markets and are curtailed when prices fall below individual resource’s threshold prices. Weighted average prices for the generation at those locations are compared to weighted average prices at Pacific Gas and Electric’s (“PG&E”) Default Load Aggregation Point (“DLAP”) to assess the impact of congestion on the resource’s performance. In addition, the MWh of curtailment are logged.

These two metrics - weighted average price of the resources compared to that of the DLAP and MWh curtailed - are used to assess effectiveness of the resources in meeting MCE’s RPS obligations at cost effective prices. If the resource’s weighted average price is near the DLAP and it has been curtailed, then the reason for curtailment is system over-supply. If the resource’s weighted average price diverges from the DLAP and it has been curtailed, then the reason for curtailment is local overgeneration that is contributing to congestion. This information is valuable feedback to MCE in locating potential future resources. If congestion and local oversupply is significant in certain areas, then MCE can determine by reviewing the CAISO’s transmission planning documents whether transmission upgrades are planned to mitigate congestion that is observed with existing resources.
17 If curtailment is caused by congestion, the impact can be somewhat mitigated by obtaining CAISO Congestion Revenue Rights (“CRRs”), which MCE has done. However, CRRs are not a perfect hedge against congestion and cannot be relied upon to mitigate congestion and subsequent economic curtailment entirely. MCE will continue to monitor and plan for managing exposure to negative market prices.
(iv) Assessment of how the Renewable Net Short Quantitative Analysis Supports the Assessment of Portfolio Supply and Demand
As reflected in MCE’s RNS appendix, MCE aims to procure sufficient quantities of renewable energy that: 1) meaningfully exceed statewide procurement mandates via internally adopted RPS procurement targets that range from 10.7% to 25.0% above the state’s interim annual RPS procurement targets throughout the planning period (2025-2035); and 2) reflect a 10% planning reserve (in excess of projected, internally adopted RPS targets that meaningfully exceed statewide mandates) to ensure that production from intermittent resources, curtailments, potential project delays or failures, and/or other unexpected circumstances that could otherwise reduce anticipated renewable energy deliveries, do not adversely impact MCE’s ability to fulfill publicly communicated renewable energy portfolio goals. These planning decisions serve as formidable protections against renewable energy delivery shortfalls. (v) Assessment of how Procurement or Allocations are Consistent with the Evaluation of Supply and Demand
MCE has assembled a broadly diverse renewable energy contract portfolio, meaning that MCE’s portfolio is attentive to technological diversity, temporal diversity, geographic diversity, and supplier diversity. These planning considerations, coupled with MCE’s voluntary procurement targets that meaningfully exceed statewide mandates, minimize sources of planning vulnerability and prevent the risk of RPS compliance shortfalls. In terms of serving customer energy 18 requirements, MCE’s diverse portfolio, which includes baseload, peak, off-peak, seasonal, and dispatchable delivery profiles, is generally complementary to the manner in which MCE’s customers use electric power. Dispatchable renewable resources, specifically co-located solar and battery infrastructure, allow for the shaping of certain renewable deliveries to promote improved alignment between supply and demand. Over time, MCE will continue to evaluate customer energy requirements and usage patterns relative to how its renewable resource portfolio delivers power and will pursue incremental procurement opportunities to better align supply and demand at least cost.

IV.A.1. Long-Term Procurement
(i) Assessment of How Current and Planned Procurement Meets 65 Percent Long-Term Contracting Procurement Requirement Through 2035.

MCE has been committed to supporting new, California-based renewable resource development since its inception, and has supported numerous generating assets via execution of long-term contracts. MCE has already executed long-term renewable contracts that are expected to yield approximately 96% of its total RPS/statutory renewable energy requirements (or 147% of MCE’s expected RPS-related long-term renewable energy requirements) in 2025. Further, most of the renewable energy supply solicited under MCE’s Open Season is intended for projects with proposed delivery terms between ten and twenty years, which bolsters MCE’s proportionate use of long-term renewable energy over time.
(ii) Quantitative Assessment of MCE’s Long Term RPS Positions The table below relates projected deliveries under MCE’s existing long-term RPS supply contracts to interim annual RPS procurement targets and related long-term contracting requirements.
19 Table 2: Projected RPS Deliveries
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
Proportionate
Long-Term
RPS Purchases
Relative to
Interim
Annual
Statutory
Procurement
Mandate 96% 95% 105% 118% 114% 108% 105% 102% 90% 85% 83% Proportionate
Long-Term
RPS Purchases
Relative to
Interim
Annual
Statutory
Long-Term
Contracting
Requirement 147% 146% 162% 182% 176% 166% 161% 157% 139% 131% 127% MCE’s substantial, ongoing commitment to long-term RPS contracting has created significant projected long-term RPS surpluses. As a result of such surpluses, there is an exceptionally low risk of MCE falling short of this aspect of the RPS compliance program.

Figure 2 depicts the relationship between California’s currently effective long-term RPS contracting mandates and projected deliveries related to MCE’s existing long-term RPS contracts, for calendar years 2025 through 2035. The rightmost bar in each grouping reflects California’s 65 percent RPS contracting mandate as 100 percent of the total long-term contracting requirement.

MCE has included two additional bars in each grouping:
1) An unadjusted projection of MCE’s expected annual long-term contract deliveries, relative to the 65 percent mandate. This bar represents the proportionate relationship between MCE’s long-term contract deliveries and the statewide procurement mandate. For example, MCE projects that it will surpass the state’s long-term contracting requirement 20 by 47 percent in 2025 and is not expecting to fall below 100 percent of its long-term contracting requirement during the current planning period; and 2) An adjusted projection of MCE’s expected annual long-term contract deliveries relative to the 65 percent procurement mandate. This bar represents the proportionate relationship between MCE’s long-term contract deliveries (including an annual reduction in such deliveries equivalent to MCE’s established Minimum Margin of Over Procurement (“MMoP”), which reflects the potential impacts of delivery shortfalls related to resources intermittency, delays in commercial operation, resource curtailment, supply chain issues, and/or other operational issues) and the statewide mandate. MCE believes that this scenario represents a relatively extreme stress case. Nonetheless, MCE would expect to meet or exceed California’s long-term contracting mandate throughout the planning period.

Figure 2: MCE’s Projected Long-Term RPS Contracting Progress: 2025-2035 21 Note that the data underlying this bar chart has been compiled annually, which means that the percentages do not reflect the additional compliance flexibility related to California’s multi-year compliance periods. For example, if MCE exceeds the long-term procurement mandate by 47% in 2025, it could absorb meaningful delivery shortfalls in the other years encompassing Compliance Period 5 before any compliance deficits arise. Unadjusted projections of MCE’s long-term contracting progress suggest that MCE is expected to exceed applicable mandates through the current planning period. Likewise, adjusted projections also suggest that MCE will similarly exceed applicable mandates, even under a relatively extreme stress case such as the one reflected in the previous bar chart. MCE expects to engage in additional long-term contract efforts, which will further increase its long-term RPS positions as well as the compliance buffer already in place.
(iii) Summary of Current and Planned Long-Term RPS Procurement MCE maintains a diverse set of long-term power purchase agreements to meet its long-term procurement needs. This includes multiple geothermal, solar, wind, small hydro and solar plus storage resources. These contracts are staggered in nature, spanning 10 to 30 years in length. In addition, MCE is engaged in negotiations to add more generating and storage resources to the existing fleet. MCE does not anticipate any issues meeting its long-term requirements. (iv) Timeline Meeting 65 Percent Long Term Procurement Requirement.

MCE did not receive an SB 155 letter and does not expect any issues in meeting its long-term RPS contracting obligations, as described elsewhere in this Plan. 22 IV.B. Portfolio Diversity and Reliability
(i) Description of How Portfolio Diversity is Considered.

As part of MCE’s forecasting and procurement processes, MCE considers the deliverability characteristics of its resources including the expected delivery profile, available capacity and dispatchability attributes, if any, associated with each of its generating resource and/or supply agreements and reviews the respective risks associated with short- and long-term purchases. These efforts lead to a more diverse resource mix, address grid integration issues, and provide value to MCE’s member communities, including reduced costs and support in achieving planned procurement objectives for the period addressed in this RPS Procurement Plan. A quantitative description of MCE’s forecast is attached in Appendix C. (ii) Description of How Planned RPS Portfolio Diversity will Contribute to System Reliability.

With respect to system reliability, MCE is aware of the planning challenges faced by retail sellers with internally adopted renewable energy targets that exceed RPS mandates. In particular, such retail sellers must often bear increased costs for renewable resources with diverse and complementary delivery profiles, as well as comparatively high levels of energy storage infrastructure to allow for the reshaping of renewable energy deliveries to better align with load.

For example, renewable energy procurement efforts that may initially focus on relatively low-cost solar resources will often necessitate subsequent investments in co-located energy storage infrastructure and/or higher-cost baseload renewable generating technologies, such as those using geothermal, biomass and landfill gas fuel sources. These baseload renewable technologies are often priced at three-to-four times the level of in-state photovoltaic (“PV”) solar generation but generally provide increased capacity value due to the more predictable, baseload generating profiles of such resources, and related reliability enhancements. 23 Despite the adverse budgetary impacts, MCE continues to pursue resource acquisitions that will promote increased alignment between supply and demand as well as the increased use of locally situated renewable generating resources. Currently, low-cost, long-term solutions are incredibly challenging to identify, as ongoing increases in California’s RPS procurement mandates and technological limitations often create the need for near-term investments to balance the achievement of compliance mandates with generalized grid reliability.

Nonetheless, MCE remains committed to pursuing a conscientious planning process that balances grid reliability, compliance demonstration, and customer cost impacts. Again, there are no easy solutions in addressing this dilemma, but MCE’s commitment to pursuing alignment of supply and demand as well as general resource diversity should contribute to grid reliability, reducing related risks for MCE’s customers and the system at large. In consideration of MCE’s diverse contractual commitments for requisite renewable energy supply and ongoing focus on the identification of RPS-eligible and complementary technologies that will mitigate reliability impacts associated with increased use of intermittent generating resources throughout the state, overall risks to system reliability associated with MCE’s RPS Procurement Plan were determined to be low.
(iii) Description of How Portfolio Diversity will Maximize Ratepayer Value While Minimizing Costs and Risks.

MCE is interested in emerging and viable technologies to meet the state’s reliability needs. MCE’s commitment to innovation and the advancement of renewable technologies continues to drive strategic opportunities for the inclusion of emerging technologies within its supply portfolio. The extent to which such technologies will be successful in mitigating conditions of oversupply, production variability and misalignments between energy production and customer use will be monitored over time to ensure that such contractual commitments are 24 promoting desired outcomes.

MCE will continue to procure renewable and other GHG-free and conventional energy products, as necessary, to ensure that the future energy needs of its customers are met in a clean, reliable, and cost-effective manner. MCE has established proportionate procurement targets for overall GHG-free energy content, including subcategories for renewable energy and other carbon-free products, including related planning reserves.

In 2020, MCE also implemented an “equivalent carbon-free” portfolio metric, which considers the total emissions associated with each supply source relative to a target annual emission factor for its entire supply portfolio. For example, MCE’s 95% carbon-free equivalent goal in 2024 contributed to the achievement of an overall portfolio emission factor less than 1% of the California Air Resources Board’s (“CARB”) assigned emission factor for energy imports and system power, which is currently set at 0.428 metric tons of carbon dioxide equivalent per megawatt hour (“MT CO2e”). Expressed differently, the 95% carbon-free equivalent goal limited, on a voluntary basis, MCE’s emissions to an overall portfolio emission factor of 0.021 MT CO2e/MWh. As reflected in its current 2024 Power Source Disclosure (“PSD”) report for Light Green service,5MCE’s actual 2024 emission factor of 0.001 MT CO2e/MWh was below the organization’s 95% carbon-free equivalent emission target (reflecting a virtual 100% carbon-free equivalency for the Light Green portfolio. The emission factors for Deep Green, Local Sol and Green Access service, as reflected in MCE’s 2024 PSD report, were also zero.

As certain renewable generating technologies are known to have relatively low levels of emissions, such as certain geothermal generating technologies, MCE’s equivalent carbon-free metric captures such impacts, along with any other use of carbon-emitting supply, including 5The 2024 Power Source disclosure Report was submitted by June 1, 2025. 25 system power and CARB-certified Asset Controlling Supply, to derive its proportionate use of carbon-free generation. To the extent that MCE’s energy needs are not fulfilled using renewable or other GHG-free generating resources, it should be assumed that such supply will be sourced from conventional energy sources, such as natural gas generating technologies or system power purchases. MCE also plans to maintain its carbon-free equivalent metric at 95% of total supply in 2025 and beyond, meaning it will be further constrained in utilizing any carbon-emitting sources, including certain renewable generating technologies. As such, MCE will continue to creatively address the exercise of resource planning and portfolio composition to meet or exceed the aforementioned carbon-free equivalency metric.

MCE uses a portfolio risk management approach in its power purchasing program, seeking low-cost supply (based on then-current market conditions) as well as diversity among technologies, production profiles, project sizes and locations, counterparties, lengths of contract, and timing of market purchases. These factors are taken into consideration when MCE engages the market and pursues related procurement activities.

A key component of this process relates to the analysis and consideration of MCE’s forward load obligations and existing supply commitments with the objectives of closely balancing supply and demand, cost/rate stability, and overall budgetary impacts, while leaving some flexibility to take advantage of market opportunities and/or technological improvements that may arise over time. MCE’s long-term load forecast is a projection of the energy (reflected in MWh) that its customers will consume annually. MCE’s long-term load forecast is driven primarily by the number and types of customers that MCE expects to serve, in conjunction with weather projections. Hourly class-specific load profiles are then used to break down the monthly energy forecast into more granular time-of-use and peak demand values. MCE’s long-term load forecast 26 also incorporates the load-modifying effects of electric vehicles, behind-the-meter solar and/or storage (via net energy metering), and energy efficiency.

MCE monitors its open positions separately for each renewable generating technology as well as GHG-free resources, conventional resources, and its aggregate supply portfolio. MCE maintains portfolio coverage targets of up to 100% of expected customer energy requirements in the near term (0 to 2 years) and typically leaves gradually larger open positions in the mid- to long-term, consistent with generally accepted industry practices. However, those larger open positions are continuously monitored for weather, market changes, and resource availabilities, and filled in a non-linear fashion as determined by MCE management. For example, MCE may fill residual summer positions ahead of the spring season or through procurements administered during the previous calendar year.

MCE prefers zero emission generating technologies, but within this preference MCE is largely technology-agnostic, subject to the previously discussed carbon-free equivalency metric.6 MCE’s supply preferences are intended to exhibit diversity across a broad range of renewable technologies that will deliver energy in a profile that is generally consistent with MCE’s anticipated load shape. MCE is aware that significant use of intermittent renewable generating technologies has the potential to create misalignments between customer energy consumption and related power production; however, MCE regularly evaluates customer usage in light of expected renewable deliveries to reduce such risks and inform future procurement decisions. Furthermore, MCE continues to consider procurement opportunities with renewable generating facilities that will utilize storage technology, which can materially re-shape the typical delivery profile 6 As mentioned above, MCE has a policy of not pursuing resource-specific nuclear power purchases.
27 associated with intermittent renewable generating assets, providing the opportunity for MCE to more accurately balance supply and changing customer demand, particularly due to the potential expansion of transportation electrification. MCE is also considering stand-alone energy storage opportunities to “recontour” purchased energy volumes in a manner that better matches changing customer usage patterns. MCE has determined that such projects are comparatively costly due to infrastructure costs and, in the case of battery storage projects, losses stemming from the common charge/discharge cycle of such projects.

Additionally, MCE offers several programs to manage its load shapes and better align MCE’s supply resources with hourly demand. For example, MCE currently offers a managed EV charging app, MCE Sync, which helps customers automate EV charging and shift consumption away from peak periods.7Additional programs to help better align supply and demand include but are not limited to: MCE’s Peak FLEXmarket;8Time of Use (“TOU”) rates;9and MCE’s revised Feed-In-Tariff (“FIT”) Plus program,10 that requires the addition of storage equal to 180% of the generator’s nameplate capacity and enables generation to be shifted outside of normal solar production hours to better align MCE resources to match the hourly load.11 Recent market data continues to indicate that midday peak resources are likely to comprise a larger proportion of California’s renewable supply portfolio due to the rapid decline in wholesale prices for solar PV generation and the abundance of such projects in operation and under development. Additions to MCE’s portfolio during the Planning Period will likely be more heavily 7 See https://www.mcecleanenergy.org/mce-sync/.
8 See https://mcecleanenergy.org/peak-flex-market/.
9 See https://mcecleanenergy.org/what-is-the-time-of-use-rate-plan/. 10 See https://www.mcecleanenergy.org/feed-in-tariff/.
11 See Agenda Item #06 from MCE’s December 2, 2021, Technical Committee Meeting, available at https://www.mcecleanenergy.org/wp-content/uploads/2021/11/MCE-Technical-Committee-Packet-December_2021.pdf. 28 weighted toward energy resources – dispatchable, shaped during non-solar or ramping periods, or otherwise – that complement competitively priced solar already under contract or pair new solar projects with storage technologies to avoid exacerbating midday over-supply. MCE may also engage in purchases from as-available renewable generation (e.g., wind) to the extent that such supply is competitively priced or otherwise provides electricity during time of day when existing supply commitments are currently lacking. Additionally, MCE is working with developers of its solar projects already under contract to add storage to those existing resources to increase the number of dispatchable resources in its portfolio. In regard to project location, MCE places the greatest value on locally-sited renewable generating and storage projects, particularly those located in its service area or within approximately 100 miles thereof. In general terms, the next highest preference related to resource selection are projects sited within the California Independent System Operator’s (“CAISO”) North of Path 15 Zone (generally, Northern California), followed by projects elsewhere in California, and lastly, out-of-state resources. This procurement strategy has led MCE to achieve its desired clean energy portfolio objectives as well as cost-competitive customer rates.
(iv) Description of How Energy Storage and Emerging Technologies are Addressed in Reliability and Diversity Planning.

Regarding new and emerging technologies, MCE has a particular interest in using offshore wind, long duration battery storage, and green hydrogen storage for building a carbon free portfolio for its customers and providing reliability to the grid. These technologies provide opportunities to shape MCE’s hourly portfolio to match the hourly demand. MCE has provided several letters of intent with the potential to get into long term agreements once the technology is commercially viable to developers of new and emerging technologies. MCE intends to continue this approach in the future.
29 IV.B.1. Forecasting for Increased Transportation Electrification A key component of the long-term load forecast includes the projections for transportation electrification load, the methodology for developing this forecast is described as follows:

MCE’s load forecast is adjusted for expected increases due to electric vehicle (“EV”) adoption. In order to estimate the impact of EV adoption on MCE’s load forecast, MCE utilizes the California Energy Commission’s (“CEC”) Integrated Energy Policy Report as the basis for the estimates. MCE utilizes the state’s mid-demand scenario, adjusting the forecasted EV load based upon two factors: 1) EV adoption rates within MCE’s service territory and 2) Participation rates within MCE’s service territory. California Department of Motor Vehicle registration data is utilized to estimate the territory’s share of the state’s forecasted EV load growth and internal customer data sources are utilized to adjust for MCE participation rates. MCE’s EV load growth forecast does not segment by vehicle types but rather adjusts the state’s total EV load based upon penetration levels.

Table 3: Transportation Electrification Load Forecast (2025-2035) Year 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 MCE
Annual EV
Load
Forecast
(GWh)
683 737 785 833 884 937 990 995 1,000 1,005 1,010
IV.B.2. Curtailment Frequency, Cost, and Forecasting
This Section responds to the questions presented in Section 4 of the ACR12 and describes MCE’s strategies and experience in managing the Agency’s exposure to negative pricing events, overgeneration, and economic curtailment for MCE’s region and portfolio of renewable resources. 12 ACR at 19-20.
30 IV.B.2.(a) Factors Having the Most Impact on the Projected Increases in Incidences of Overgeneration and Negative Market Price Hours Due in large part to the rapid increase in the amount of wind and solar generation coming online throughout the western United States, the CAISO Balancing Authority Area (“BAA”) has experienced an increasing frequency and magnitude of curtailment and negative pricing events.

The U.S. Energy Information Agency (“EIA”) estimates that as of March 2025, California has 41,262 MW of total installed solar capacity, with 18,706 MW of that total being behind-the meter solar.13 The CAISO reports that it has approximately 21,240 MW of utility-scale solar and 8,373 MW of utility-scale wind currently installed within its BAA.14 This capacity results in discrete periods where the majority of load in the CAISO is served by solar and wind resources. The monthly maximum load served by wind and solar in the CAISO has averaged 87.5% over the past 5 years (April 2020 to April 2025), and the monthly maximum load served by wind and solar exceeded 142%.15
To address the resulting instances of over-supply, the amount of curtailment of wind and solar in the CAISO has significantly increased each year from 2015 through 2022, totaling 187,000 MWh in 2015, 308,000 MWh in 2016, 358,000 MWh in 2017, 461,000 MWh in 2018, 961,000 MWh in 2019, 1,587,497 MWh in 2020, 1,504,803 in 2021, 2,449,248 in 2022 2,659,526 MWh in 2023, and 3,423,376 in 2024. As of June 12, 2025, the total curtailment of solar and wind year to date is 2,290,000 MWh. Curtailment is typically the highest during the months of March, April, 13 EIA, Electric Power Monthly, Table 6.2.B. Net Summer Capacity Using Primarily Renewable Energy Sources and by State, March 2025 and 2024 (Megawatts), available at:
https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=table_6_02_b.. 14 CAISO, What are we doing to green the grid?, updated April, 2024, at https://www.caiso.com/about/our-business/managing-the-evolving-grid 15 https://www.caiso.com/documents/monthly-renewables-performance-report-april-2025.html CAISO, Monthly Renewables Performance Report, April 2025, available at https://www.caiso.com/documents/monthlyrenewablesperformancereport-feb2024.html 31 and May when hydroelectric generation is historically at its highest and California load is at its lowest. Years in which there is an above-average snowpack results in higher-than-average hydroelectric generation which exacerbates renewable generation curtailment. The table below summarizes solar and wind curtailment from January 2025 through April 2025 Table 4: Summary of CAISO Solar and Wind Curtailment January-April 2025 2025 Data Wind Curtailment
(MWh)
Solar Curtailment
(MWh)
January 15,300 114,970
February 22,890 479,630
March 61,840 857,180
April 51,480 686,710
Total Curtailment 151,510 2,138,490
Curtailment % 2.02 % 13.68%
No. of Intervals Curtailed 14,841 16,728
Pct. of Intervals Curtailed 34.14 38.48
Annual Curtailment (MWh)
Wind Solar
2018 28,686 432,357
2019 43,557 921,684
2020 90,276 1,497,220
2021 78,477 1,426,326
2022 128,990 2,320,258
2023 150,604 2,508,916
2024 230,765 3,192,612
32 2025 (Partial Year*) 151,510 2,138,490
Annual Curtailment (% of Specific Generation)
2018 0.17% 1.56%
2019 0.27% 3.22%
2020 0.56% 4.99%
2021 0.41% 4.19%
2022 0.70% 6.26%
2023 0.72% 6.10%
2024 1.03% 6.29%
2025 (Partial Year*) 2.02% 13.68%
Average 0.55% 4.66%
Annual Curtailment (% of Load)
2018 0.013% 0.190%
2019 0.020% 0.420%
2020 0.041% 0.680%
2021 0.036% 0.650%
2022 0.057% 1.030%
2023 0.069% 1.148%
2024 0.103% 1.419%
2025 (Partial Year*) 0.227% 3.210%
Average 0.071% 1.093%
33 *Through April 2025
The CAISO notes that the majority of renewable resource curtailment is “a result of economic downward dispatch, rather than self-schedule curtailment,” and that “[m]ost renewable generation dispatched down in the ISO were solar resources, rather than wind, because solar resources typically bid more economic downward capacity than wind resources”.16 That means that curtailment happened in response to congestion and was mitigated by supply that was willing to reduce its output based on price signals from the CAISO market.

CAISO system-wide 2025 curtailment percentages are higher than forecasted by MCE to date. Thus far in 2025 through May, MCE has experienced 85,404 MWh of curtailment, which is over 11.2% of MCE’s RPS portfolio. This percentage will likely decrease as the summer season progresses. Curtailment to MCE’s RPS portfolio is predominantly composed of the Little Bear Solar resources, which is 93.3% of MCE’s curtailment volume. MCE has been in discussions with the CAISO regarding local network upgrades required and the potential for adding a battery to the project to alleviate Little Bear Solar curtailment.

IV.B.2.(b). Written Description of Quantitative Analysis of Forecast of the Number of Hours Per Year of Negative Market Pricing for the Next 10 Years MCE’s scheduling coordinator agent, ZGlobal, has the capability to perform production cost analyses based on various input assumptions through 2035 to derive hourly market prices for energy and ancillary services. PLEXOS Integrated Energy Model is a commercial optimization engine that can simulate the economic commitment and dispatch used by the CAISO’s day-ahead 16 CAISO, 2020 Annual Report on Market Issues and Performance Report, published January 20, 2022, page 41, available at http://www.caiso.com/Documents/2020-Annual-Report-on-Market-Issues-and-Performance.pdf. 34 market processes which simultaneously optimizes energy dispatch and ancillary services capacity awards across the CAISO grid. In this way, the simulation will determine locational marginal prices and ancillary service marginal prices in the same manner the CAISO day-ahead market sets prices. ZGlobal has developed models using input assumptions that are based on common case inputs and planning guidelines from Western Electricity Coordinating Council, CAISO, Commission and CEC.

The key assumptions considered for the assessment included the impact of higher California renewable energy standards (60% RPS by 2030), planned gas-fired and nuclear generation retirements and adopted CEC demand forecasts which consider energy efficiency programs and increased behind-the-meter solar generation. Results are highly dependent upon input assumptions, primarily the level of new RPS generation, deployment of energy storage facilities, upgrades to CAISO-controlled transmission facilities and the ability to export energy from the CAISO to external balancing areas.

In California, electricity prices are typically set by gas-fired resources operating on the margin. However, as increasing supplies of renewable energy are added to the system, there are periods where marginal prices are being set by zero or even negatively-priced resources. Market prices have been trending downward, especially during seasons and periods of the day when loads are low and solar output is high with the influx of renewable energy resources. The modeling shows that during solar hours, prices are low during the middle of the day, driven by solar resources and their willingness to curtail and increasing in the morning and evening when gas-fired resources are needed to meet peak loads outside of the solar supply period. In short, prices as reflected by the CAISO’s duck curve are expected to continue, with the amplitude of the valley and ramps dictated by the amount of energy storage available to smooth out the net supply. 35 IV.B.2.(c) Experience, to Date, With Managing Exposure to Negative Market Prices and/or Lessons Learned from Other Retail Sellers in California MCE’s experience and process for managing exposure to negative market prices has been addressed above in Section IV.A.(iii).

IV.B.2.(d) Direct Costs Incurred, to Date, for Incidences of Overgeneration and Associated Negative Market Prices
For calendar year 2025 through May, MCE’s RPS portfolio has been exposed to negative market prices and experienced curtailment as summarized in the table below.

Table 5: Summary of MCE RPS Resources Curtailment January-May 2025 Location Day-Ahead
Negative Prices
Real-Time
Negative Prices
Curtailment
(MWh)
Cost of
Curtailment ($)
South P26 -$10.79 -$16.59 1,711 $69,151
Fresno 1 -$36.83 -$43.49 79,701 $3,798,396
Fresno 2 -$18.78 -$24.52 997 $48,777
North P26 -$11.77 -$16.52 2,995 $110,174
Total -$22.41 85,404 $4,026,499
The Day-Ahead and Real-Time Negative Price columns represent averages of negative prices by RPS geographic area when prices are negative for solar hours for solar resources and all hours for wind resources. The prices are averages based on resources within the area. Curtailment MWh is the amount of energy that MCE RPS resources in the areas were curtailed from January 1 through May 31, 2025. “Cost of Curtailment” is the subsequent market cost of the curtailed energy.
36 IV.B.2.(e) An Overall Strategy for Managing the Overall Cost Impact of Increasing Incidences of Overgeneration and Negative Market Prices While curtailment is a viable renewable integration strategy that is generally more cost-effective than other options, there are potential negative consequences from excessive curtailment.

Curtailment of solar and wind represents a lost opportunity to generate zero-GHG electricity, and excessive curtailment could impact the ability of the state to meet its environmental and energy policy goals. Additionally, these over-supply situations expose ratepayers to increased costs because their load serving entities must either economically curtail the generating resource (and often pay for the electricity that was not generated) or generate power and be exposed to negative prices.

MCE considers the impact of curtailment and negative pricing on its portfolio and factors potential curtailment into its long-term planning. Due to the difficulty in accurately forecasting curtailment, MCE will review the historical data on curtailment and negative pricing within regions where MCE may contract for generating resources. When MCE is evaluating new procurement opportunities, the potential amount of future curtailment is one factor that MCE considers. While MCE has not yet developed an individualized forecast of future curtailment, MCE will factor potential curtailment into its minimum margin of procurement (described in Section IX) and may also factor this consideration in future iterations of its Risk Assessment (Section VII). To the extent that MCE is engaged in renewable supply agreements which include curtailment provisions, it will take actions to limit the impacts of curtailment on its customers.

During its current and future renewable contracting efforts, MCE will pursue contract terms that recognize and limit the potential financial impacts of negative pricing and give MCE greater flexibility to direct economic curtailment, if this becomes necessary. 37 IV.B.2.(f)Contract Terms Included in RPS Contracts Intended to Reduce the Likelihood of Curtailment or Protect Against Negative Prices.

MCE negotiates the right in its long-term Power Purchase Agreements (“PPA”) to economically curtail deliveries to a certain number of hours up to which there is no seller compensation. MCE also has a strong preference to be the scheduling coordinator so that it can adjust its bidding strategies to protect against negative pricing in the Day Ahead and Real Time markets.

IV.C. Portfolio Optimization
MCE plans for and secures commitments from a diverse portfolio of generating resources to reliably serve the electricity supply requirements of its customers over near-term, mid-term and long-term planning horizons. MCE’s goal is to meet organizational policies and statewide mandates in a manner that is cost effective, achieves internally adopted clean energy objectives, promotes grid reliability, and generally supports a well-balanced and diversified resource portfolio.

Portfolio optimization strategies can help reduce costs and should facilitate alignment of MCE’s portfolio of resources with its forecasted needs. This noted, MCE continues to pursue its renewable energy procurement goals through the exclusive use of PCC1 products but remains aware of the diminished availability of this supply during Compliance Period 5. If alternative RPS-eligible products become necessary to meet MCE’s near-term portfolio objectives, MCE will consider these alternatives as appropriate. MCE’s preference for PCC1 RPS products is expected to minimize portfolio emission impacts that would otherwise accrue using Portfolio Content Category 2 (“PCC2”) and Portfolio Content Category 3 (“PCC3”) product options, both of which are ascribed emissions under California’s current emissions calculation methodology. While this approach is more costly it promotes the achievement of MCE’s GHG-related objectives. This noted, MCE may procure small quantities of RPS supply from clean and specified PCC2 resources 38 if unexpected delivery shortfalls are higher than expected retail sales and/or prevailing market conditions necessitate such purchases. MCE anticipates such purchases to be rare, if purchased at all. This flexibility to purchase PCC2 resources ensures that MCE can fulfill adopted portfolio commitments to its customers. MCE will advise the Commission if the Agency anticipates any deviations from the aforementioned resource preferences.

To support its RPS planning and procurement goals, MCE considers the following strategies:
● Joint Solicitations: Joint solicitations can expand the procurement opportunities available to a CCA, as well as provide procedural efficiencies, economies of scale, and overall cost savings for participating organizations. MCE is closely networked with other CCAs through its membership in the CalCCA, the trade organization representing California’s CCA sector, and regularly coordinates with other CCAs regarding prospective procurement opportunities and portfolio balancing activities. ● Purchases from Retail Sellers: Purchases of RPS-eligible renewable energy from other retail sellers can provide a cost-effective way of meeting short-term resource needs or filling in gaps in procurement while long-term projects are under development. MCE will evaluate solicitations offered by other retail sellers, as necessary. ● Sales Solicitations: As MCE continues to manage its growing portfolio of renewable resources, it will also consider administering sales solicitations (serving as a renewable energy seller) for the benefit of other retail sellers. Such solicitations are expected to be rare and relatively small in scale. MCE may also engage in bilateral sales discussions with certain retail sellers, including CCAs, if/when divesting relatively small amounts of surplus renewable energy supply is deemed necessary to rebalance MCE’s renewable portfolio 39 relative to internally established procurement targets. MCE has completed such processes in the past and expects to do so in the future as well. Selling excess renewable supply is an effective way for all LSEs to reduce unnecessary renewable energy expenses while providing valuable renewable energy products to other market participants. ● Optimizing Existing Procurement: As MCE considers its long-term resource needs, it may evaluate options in its future PPAs to increase the output of existing generating facilities through technological upgrades. This can be accomplished by adding new capacity to an existing generator or by adding energy storage infrastructure to an existing renewable generator. Expanding existing facilities may provide additional generation at reduced costs with a lower risk of project failure because the need for distribution system upgrades and permitting may be minimized or eliminated. Adding energy storage infrastructure to an existing renewable generator enhances grid reliability and the value of electric energy produced by the generating facility. Such enhancements allow pre-storage energy delivery profiles to be shifted to: 1) better align MCE’s supply with customer demand; or 2) create more value for MCE customers by shifting electric energy deliveries to a time of day when market revenues (related to such energy deliveries) would be greater than normal. In terms of reliability impacts related to the addition of energy storage infrastructure, MCE expects that such enhancements would meaningfully increase the proportionate level of RA capacity that could be derived from an intermittent renewable generating resource. It is well documented that without such storage infrastructure, there will be reductions to the Net Qualifying Capacity (“NQC”) of intermittent renewable generating resources, resulting in very little capacity benefits from solar-only generating projects. In considering these sorts of enhancements, MCE will be mindful of the need to coordinate with its 40 resource owners/operators to evaluate potential planning constraints (e.g., generator interconnection processes and limitations) before determining that the addition of energy storage infrastructure at an existing generating facility would be a viable option.

MCE launched a Request for Information (“RFI”) for Long-term Offers on April 14, 2025.17 The results of the RFI will inform MCE’s approach to its typical Open Season solicitation process. Open Season provides a competitive, objectively administered opportunity for qualified suppliers of various energy products (including renewable and storage technologies) to fulfill MCE’s future resource requirements and compliance obligations. Open Season is typically administered on an annual basis for purposes of soliciting offers for new-build renewable energy and storage resources and capacity that meet the procurement targets set forth in IRP. The 2025 Open Season will focus on soliciting resources that will provide the best value and best fit for MCE load shapes, in addition to supporting MCE’s compliance with regulatory procurement requirements.

As part of the Open Season solicitation process, MCE provides a Procedural Overview and Instructions document that describes the Open Season process, schedule, and requirements for submitting a conforming offer. MCE also provides an offer form and term sheets that must be submitted along with the offer.

During this year’s RFI, MCE sought information from qualified suppliers of renewable energy, energy storage products and RA to inform MCE’s formal long-term offer solicitation in 2025. MCE’s procurement team launched an RFI as an initial step in its long-term procurement efforts in 2025. MCE believed that this new approach would streamline procurement efforts for all participants. MCE sought information for prospective full-toll agreements (all applicable 17 See https://www.mcecleanenergy.org/energy-procurement/. 41 products) with a minimum contract term length of at least five (5) years from Renewable Energy (PCC1-eligible) projects, Renewable Energy Paired with Energy Storage projects, and Standalone Energy Storage projects. Projects were to be no less than 5 MW for 24x7 load profiles or no less than 25 MW for intermittent resources. Beyond these categories, responses were not limited in any other respect. Due to numerous headwinds in the market for grid-scale projects, including interconnection delays and process reforms, permitting challenges, and federal tax credit and tariff uncertainty, MCE sought a new approach to its long-term procurement in 2025. The procurement team believed a streamlined RFI process would provide an indication of the current landscape for projects in all stages of development. The Procurement team worked closely with MCE’s Public Affairs team, leveraged external stakeholders, including CalCCA, and communicated with an extensive network of developers to draw participation in the RFI. MCE will continue to evaluate the RFI results and may pursue a formal Request for Offers (“RFO”) from qualified respondents.

When an offer is received, MCE first reviews an offer for completeness relative to the RFO eligibility criteria. MCE then conducts a quantitative analysis focused on the value of each conforming offer, in addition to a qualitative review evaluating non-quantitative offer details, like interconnection status, in more depth. MCE selects the strongest offers on a rolling basis, in parallel to completing evaluations of other offers as they are submitted. To ensure that favorable opportunities are not “lost” to other buyers, MCE works with the 3rd party to enter into an Exclusivity Agreement once an offer has been short-listed.

Once an Exclusivity Agreement is executed, Staff will begin contract negotiations with the shortlisted projects. The resulting PPAs and Energy Storage Agreement(s) (“ESA”) are reviewed by MCE’s Executive Management team before review and approval by MCE’s Board. Contract execution occurs after the agreements are approved by the Board. 42 MCE also considers allocations from PG&E in its portfolio optimization. Through the Power Charge Indifference Adjustment (“PCIA”), MCE customers (and other CCA and Direct Access customers) are required to pay their share of the above-market costs associated with PG&E’s legacy resources such as its large hydroelectric fleet, PG&E’s nuclear power plant, Diablo Canyon, and many PG&E PPAs including RPS PPAs. As nearly half of PG&E’s customer load has departed for other LSEs, it has resulted in PG&E having excess resources in its portfolio.

Accordingly, the Commission directed PG&E to offer a proportionate share allocation of output from hydroelectric and nuclear, GHG-free, resources at no additional cost on a voluntary basis to CCAs and Direct Access providers whose customers pay the PCIA for the years 2019 and 2020. (“Interim Allocation” The Interim Allocation was extended into 2021 by Resolution E-5111, in which the Commission also authorized PG&E to extend the interim approach to GHG-Free resources through December 31, 2023.). In Decision (“D.”) 23-06-06 the Commission modified the PCIA methodology by allowing PG&E to elect to either offer an allocation of large hydro GHG-Free attributes or to retain the attributes and value them at a new market price benchmark.

In Advice Letter 7005-E, PG&E notified LSEs of its intent to offer large hydro allocations for 2024, and in its 2025 Energy Resource Recovery Application PG&E notified parties of its intent to offer large hydro allocations for the 2025-2027 period as well. MCE’s Board in late 2024, accepted the hydro allocations as well as 2025 nuclear allocations. MCE will use these allocations in meeting its internally adopted GHG-free targets. Additionally, MCE structured its Light Green portfolio to be approximately 95% GHG-free starting in 2023,18 subject to market and/or regulatory changes. To structure such a clean Light Green portfolio by 2023, MCE procured three 18 MCE’s Operational Integrated Resource Plan, https://www.mcecleanenergy.org/wp-content/uploads/2022/11/MCE-Operational-Integrated-Resource-Plan_2023.pdf. 43 products: (1) RPS-eligible renewable energy; (2) large hydroelectric energy; and (3) Asset Controlling Supplier energy, the vast majority of which is attributable to large hydroelectric generating resources. To ensure grid reliability, MCE’s contracting goals include 475 MW of stand-alone energy storage to be online by 2030, and to have approximately 153 MW of new energy storage paired with solar resources online by 2030.19 Disadvantaged Community Solar Green Tariff: In 2021, MCE launched its first solicitation for the Green Access (“Disadvantage Community – Green Tariff” or “DAC-GT”) and Community Solar Connection (“DAC-CSGT”) procurement process (“2021 Green Tariff”). The purpose of MCE’s 2021 Green Tariff was to fulfill the requirements of AB 327, D.18-06-027, D.18-10-007, and Resolution E-4999 (collectively the “Green Tariff policy”). The Green Tariff policy is intended to promote the installation of renewable generation among residential customers in disadvantaged communities (“DACs”). MCE executed two contracts for the DAC-GT program.

To comply with the Green Tariff policy, MCE has to procure under two programs: 1) Green Access and 2) Community Solar Connection. MCE fulfilled the requirements of the Green Access program through the selected projects from the 2021 solicitation. MCE held annual solicitations for the Community Solar Connection program in 2022 and 2023 and received no offers. MCE then opened the Community Solar Connection solicitation in 2024 on an open until filled basis with no offers received. On May 30, 2024, the CPUC issued D.24-05-065, which made several modifications to the DAC-GT program, including adopting changes to the cost cap for the program, and closing the Community Solar Connection program, rolling unused capacity into the DAC-GT program. MCE is currently evaluating and will likely release a solicitation addressing 19 MCE’s 2022 CPUC Integrated Resource Plan, https://www.mcecleanenergy.org/wp-content/uploads/2022/11/MCE-2022-Integrated-Resource-Plan_11012022.pdf. 44 both these elements.

On June 24, 2021, the Commission adopted D.21-06-035, which directed all retail sellers to collectively procure 11,500 MW of new NQC, including LLT resources to come online between 2023 and 2026. This decision assigned each retail seller a specific procurement responsibility based on its share of peak demand. In February 2023, the Commission issued D.23-02-040, which supplemented the initial Mid-Time Reliability (“MTR”) order to require LSEs to procure an additional 4,000 MW of NQC and pushing out the online date for LLT resources to 2028. MCE’s total obligation, resulting from these two CPUC decisions, is 454 MW of NQC by June 1, 2028.

MCE’s 454 MW requirement includes 72 MW of NQC from dispatchable, zero-emitting capacity, required to be online by June 1, 2025. As part of its 454 MW requirement, MCE must also procure at least 58 MW of LLT resources, including (1) 29 NQC MW from long duration storage resources by June 1, 2028; and (2) 29 NQC MW from firm, non-fossil fueled baseload generating resources by June 1, 2028.20 MCE plans to meet its MTR obligations using a diverse set of resource technologies, some of which will be RPS-eligible. MCE has negotiated a number of ESAs and PPAs to meet its MTR obligations and has executed agreements for RPS-eligible resources related to MTR.21 As discussed in Section V below, pursuant to the Commission’s initial MTR order, MCE has eight executed contracts for projects under development that will be used to meet MTR mandates: Daggett, Golden Fields, Geysers, Humboldt House, Strauss Wind, Key, Cormorant, and Corby. MCE’s RNS, Project Development Status, and Cost Quantification templates have also been updated to incorporate these eight projects.
20 Pursuant to D.23-02-040, the Commission changed the required online dates for LLT resources from 2026 to 2028.
21 See Renewable Net Short Template Row Fb.
45 Generally, the MTR decisions are aligned with MCE’s internally adopted contracting goals, which are highlighted above. As noted above, MCE provided approximately 99% GHG-free and 69% renewable energy through its Light Green base product in 2024, as shown in MCE’s 2024 PSD Report. All other MCE customers, including those participating in the Deep Green, Local Sol, and Green Access service options, received supply reflecting 100% renewable and zero carbon emissions in 2024.

MCE intends to use RPS-eligible resources acquired for the MTR procurement mandates to fill open positions relative to MCE’s internal RPS goal.22 MCE will continue to use procurement strategies such as joint contracting efforts, buying from other retail sellers, and optimizing existing procurement, as described earlier in this section, to meet the MTR procurement mandates and MCE’s internal goals for RPS at the lowest cost to its customers.

IV.C.1 Conformance with the IRP Proceeding
The resources identified in this RPS Procurement Plan are consistent with the resources MCE expects to identify in MCE’s 2025 IRP, which is currently required to be submitted to the Commission for certification by November 1, 2025.23 MCE’s RPS Procurement Plan is also consistent with the biannual MTR updates provided to the Commission addressing MCE’s progress towards meeting procurement requirements under D.21-06-035 and D.23-02-040.24 As required by the ACR,25 specifically, Table 6below describes how MCE’s 2025 RPS Procurement 22 See Row Ga of the Renewable New Short Template.
23 While Commission decision indicates that LSEs are to submit 2025 IRP to the Commission by November 1, 2025, Energy Division indicated via email on June 5, 2025 that the IRP timeline will be delayed.
24 Since filing its 2022 Compliance IRP, MCE has filed six biannual MTR update filings on February 1, 2023, August 1, 2023, December 1, 2023, June 3, 2024, December 2, 2024, and June 2, 2025 respectively.
25 ACR at 21-22.
46 Plan conforms with the determinations made in the IRP Proceedings (R.16-02-007 and R.20-05- 003) and highlights the interrelationships of its RPS and IRP planning processes. The following table reflects MCE’s current updates, as reflected in this RPS Procurement Plan, regarding RPS alignment with the 2024-2026 IRP process.

Table 6: RPS Alignment in MCE’s IRP
IRP Section
Subsection
RPS Alignment in IRP
III. Study Results
A. Conforming and
Alternative
Portfolios
Retail sellers should explain how the RPS resources they plan to procure, outlined in their RPS Plan, will align with each of their Conforming Portfolios being developed in their IRP Plans for Commission approval and certification. This explanation should include:

1. Existing RPS resources
that the retail seller owns
or contracts.

2. Existing RPS resources
that the retail seller plans
to contract with in the
future.

3. New RPS resources that
the retail seller plans to
invest in.

4. New and existing
resources that will be used
to meet Mid-Term
Reliability obligations
adopted in D.21-06-035
and the supplemental
procurement ordered in
D.23-02-040.

The Commission certified MCE’s 2022
IRP per Ordering Paragraph 5 of D.24-02-
047. Pursuant to D.24-02-047 and the
Assigned Commissioner’s Amended
Scoping Memo and Ruling Extending
Statutory Deadline, issued April 18, 2024,
MCE’s next full update to its 2022
Compliance IRP will be filed by
November 1, 2025, although this filing
date is subject to change due to delay in
the Commission’s issuance of filing
materials and guidance.

MCE’s portfolio mix and planned
procurement met the requirements of the
2022 IRP Preferred Conforming Portfolio
(“PCP”) in the last IRP cycle and met
MCE’s compliance and internal
obligations and targets. Looking forward
to the upcoming 2025 IRP, MCE
anticipates that its planned procurement of
a diverse set of renewable resources, as
represented in its 2022 PCP and as
supplemented and complemented with
additional near-, mid-, and long-term
procurement, will meet the Commission’s
47 mandated emissions targets and reliability
metrics, including the balanced and
diverse set of resources identified in the
most recent (2023) preferred system plan
adopted by the Commission. MCE's PCP
procured to the lower emissions target that
was adopted in the 2023 PSP. As such,
MCE expects that its portfolio will
comply with the emissions metrics of the
current Preferred System Plan and the
emissions metrics in the upcoming IRP
cycle. However, MCE notes that until
official guidance and requirements for the
2025 IRP cycle are issued by the
Commission, MCE cannot state with
certainty what its optimal long-term
procurement plan will be. To remain
resilient and flexible, MCE has not set a
specific ratio on the characteristics or type
of resources for its planned procurement.

The right balance will depend on multiple
factors including but not limited to;
• Specific and final IRP requirements;
• Availability of eligible resource types
on the market;
• Project development timelines;
• Deliverability of available resources
for contracting;
• Price and affordability;
• Location and congestion analysis; and
• MCE Portfolio fit.
• For reference, a description MCE’s
PCP is as follows:
● MCE’s PCP achieves an overall
portfolio GHG target below MCE’s
assigned share of the 2030 and 2035
emissions under both the 30 million
metric tons (“MMT”) and 25 MMT
scenarios.
● Using the CPUC’s embedded
assumptions in the 25 MMT portfolio,
48 MCE’s emissions registered at 0.493
MMT relative to MCE’s assigned
share of 0.640 MMT in 2030 and

0.492 MMT relative to 0.504 MMT in
2035.
● MCE’s PCP assumed the use of RPS
resources that were reflected in
MCE’s supply portfolio at the time of
the 2022 IRP filing.
● The planned RPS-eligible resources
reflected in MCE’s PCP included: 109
MW geothermal; 356 MW wind
(consisting of in-state, out-of-state,
and off-shore); and 222 MW solar
o Of the aforementioned PCP
resources, MCE anticipated the
following new RPS-eligible
capacity additions: new hybrid
resources totaling 212 MW solar/
153 MW battery storage, 109
MW of geothermal, and new wind
resources totaling 265 MWs.
● MCE also continues to procure and
develop projects (both renewable
generation paired with storage and
stand-alone storage) to meet its MTR
requirements pursuant to D.21-06-035
and D.23-02-040 (MCE was assigned
332 MW of incremental Net
Qualifying Capacity to meet its share
of the state’s MTR need pursuant to
D.21-06-035 and was assigned an
additional 122 MW of incremental
NQC to be online by 2027 pursuant to
D.23-02-040). MCE continues to
actively procure to meet the initial
MTR need, the supplemental MTR
need, and RPS-related needs in
compliance with the mandated
timelines. All of this procurement
contributes towards MCE’s MTR- and
IRP-related needs, and much, but not
49 all, of the procurement will contribute
towards MCE’s RPS-related
requirements. At the time of this
filing, MCE’s existing executed MTR
agreements or new build RPS-eligible
procurement include the following
incremental capacity amounts: 27 MW
of nameplate geothermal capacity; 100
MW nameplate solar paired with 92
MW of nameplate storage; and 110
MW of nameplate solar paired with 60
MW of nameplate storage, 93.35 MW
of nameplate wind capacity, and 110
MW of nameplate solar paired with
110 MW of storage. Although not
MTR-eligible, MCE has also procured
and brought online 100 MW of
energy-only solar capacity from a
new-build solar facility. All of the
referenced procurement contributes
towards the diverse set of resources
indicated in MCE’s 2022 PCP, which
portfolio will continue to be revised
and supplemented to account for
market conditions, regulatory
requirements, and internal portfolio
optimization needs.
● MCE is also taking action via its
annual solicitation processes to
identify additional projects that
contribute towards MCE’s MTR, RPS,
and general IRP needs through formal
RFIs and RFOs as well as pursuing
bilateral opportunities with project
developers as described in more detail
in Section IV.C, above. MCE expects
that some of this procurement will be
eligible to contribute towards MCE’s
RPS needs; all of this procurement is
expected to contribute towards MCE’s
existing MTR needs and existing and
future IRP procurement obligations to
support reliability and GHG reduction
50 efforts. Through administration of
MCE’s RFI procurement process,
MCE is seeking to reduce outstanding
resource needs required to meet
portfolio specifications reflected in its
PCP, MTR requirements, as well as
any other internal and state-mandated
RPS or reliability procurement targets.

To the extent additional resources are
needed, MCE is conducting
supplemental, smaller solicitations and
pursuing bilateral negotiations.
● Separate from, and predating the RFI,
MCE is also pursuing various new-build projects for wind capacity, additional geothermal capacity, and
co-located solar and storage capacity
that MCE expects to be under contact
within the year or soon thereafter.
● In addition to the more formal
solicitation processes, MCE also
solicits offers for short-term PCC1
renewable energy purchases/sales for
annual portfolio balancing.

Additionally, MCE participated in the
PG&E Voluntary Allocation and
Market Offer (“VAMO”) process and
received an allocation of renewable
energy from the PG&E’s PCIA
portfolio in 2024. MCE is no longer
receiving allocations from this
process.

Any IV. Action
Plan
A. Proposed
Activities
Retail sellers should describe how they propose to use RPS resources to implement both Conforming Portfolios. Narratives should include:

1. Proposed RPS
procurement activities as
required by Commission
decision or mandated
procurement.

To ensure compliance with its IRP, GHG,
reliability, and RPS targets, MCE plans to
substantially rely on GHG-free and RPS-eligible resources while contributing to statewide reliability requirements and
51 2. Procurement plans,
potential barriers, and
resource viability for each
new RPS resource
identified.
responsibly managing overall portfolio
costs.

As described above in the Study Results
section, there is significant overlap among
MCE’s RPS-related procurement, IRP-related procurement, and MTR-related procurement. MCE has contracted for
three co-located resources, which are
expected to provide additional RPS- and
MTR-eligible incremental capacity (one of
which is online, the other two resources
are expected to achieve commercial
operation in August 2025 and April 2031,
respectively).

MCE’s prior RPS procurement plan also
indicated MCE had four contracts for
geothermal capacity (3 of which were
incremental, new build capacity; 1 is for
100 MW of existing geothermal capacity
for a 10-year delivery period starting in
2027). As of this filing, and as has been
previously reported to the Commission in
prior RPS- or MTR-related filings, due to
contract failure of one of the incremental
geothermal projects, MCE now has three
recently procured geothermal projects
under contract (2 of which are incremental
geothermal capacity eligible to count
towards MTR requirements). All of the
aforementioned geothermal procurement
is under long-term contract. Of note, one
of the aforementioned incremental
projects (representing 7 MW of
geothermal capacity) achieved
commercial operation in June 2025 and is
actively contributing towards MCE’s
reliability, emissions, and RPS needs. The
other incremental geothermal project
(representing 20 MW of nameplate
capacity) has encountered a number of
material delays due to interconnection and
permitting. These delays will require
material changes to critical contract
milestones, including construction start
52 and commercial operation, both of which
MCE expects to be achieved before 2030.

For more detailed descriptions of MCE’s
MTR procurement, please refer to MCE’s
biannual MTR update filings, the latest of
which was filed on June 2, 2025.

MCE is also actively pursuing various
new-build projects for wind capacity,
additional geothermal capacity, and co-located solar and storage capacity, as mentioned in the Study Results Section
above and throughout this RPS Plan.

MCE expects these resources to be under
contact within the year or soon thereafter.

IV. Action Plan
B. Procurement
Activities
The retail seller should describe the solicitation strategies for the RPS resources that will be included in both Conforming Portfolios. This description should include:

1. The type of solicitation.

2. The timeline for each
solicitation.

3. Desired online dates.

4. Other relevant
procurement planning
information, such as
solicitation goals and
objectives.

MCE will issue future solicitations, as
described above in Section X, on a
timeline that is appropriate for the
resource development plan that is:
responsive to the anticipated needs for the
upcoming 2025 IRP cycle; consistent with
MTR procurement timelines and
attributes; conducive to MCE meeting its
internal and state-mandated RPS targets.

As part of such processes, MCE may
pursue additional resources that will be
needed to fulfill resource specifications
reflected in its own portfolio needs, to
meet MTR requirements or future
potential mandates or CPUC procurement
program, upcoming IRP requirements.

Responsive to current portfolio needs, and
in anticipation of future needs, MCE’s
current RFI process is specifically
targeting PCC 1-eligible renewable energy
generating facilities that may be paired
with energy storage and/or renewable
baseload capacity. MCE is currently
53 evaluating responses to this RFI and
expects to launch a subsequent RFO
and/or commence discussions with
potential project developers bilaterally to
try to secure projects that can meet MCE’s
current and anticipated RPS, IRP, and
MTR needs. In addition to the more
formal solicitation processes, MCE also
solicits offers for short term PCC1
renewable energy purchases/sales for
annual portfolio balancing.

IV. Action Plan
C. Potential
Barriers
Retail sellers should provide a summary of the potential barriers to implementing both Conforming Portfolios as they relate to RPS resources. The section should include:

1. Key market, regulatory,
financial, or other
resource viability barriers
or risks associated with
the RPS resources coming
online in both retail
sellers’ Preferred
Portfolios.

2. Key risks associated
with the potential
retirement of existing RPS
resources on which the
retail seller intends to rely
in the future.

MCE notes that even though a balanced,
diverse RPS portfolio is desirable, the
limited resource availability and lead time
required for some technology types will
necessitate planning flexibility. While
MCE has a highly successful track record
of contracting with new-build renewable
resources, there is always a risk of project
failure due to market and regulatory
conditions beyond MCE’s control. Of
increasing concern to MCE is the
backlogged interconnection queue and
delays in processing the numbers of
applications for interconnection studies
and deliverability. Restrictions and
uncertainty on this front increase risk and
uncertainty for LSEs and can ultimately
present a material barrier to LSEs bringing
on new RPS resources that have sufficient
deliverability to meet RPS program and
reliability needs. Importantly,
transmission and interconnection issues
not only affect the viability of projects at
the outset, but impact the on-going
economics of projects once the generation
is online – this is particularly relevant for
non-dispatchable renewable projects that
are subject to curtailment due to
54 insufficient transmission. Adding to this
constraint are lingering supply chain
issues and permitting delays that impact
timely development and interconnection
of new resources.

MCE also notes that potential changes to
federal tax policy threaten to materially
impact renewable energy development in
California – the full impacts of which are
yet to be determined.

IV.C.2. Response to Local and Regional Policies
(i) Responsiveness to Policies of MCE Governing Board
MCE is a local governmental agency that is subject to the control of its governing board and is directly accountable to the community that it serves. MCE strongly supports and is committed to meeting the state’s GHG reduction and renewable procurement goals. As a member of CalCCA, MCE actively supported the passage of SB 100 (2018) and has fully incorporated the procurement requirements of the state’s RPS program into its overall procurement strategy.

As previously noted, MCE’s internally adopted renewable energy procurement target has been set at 60% (through 2025, increasing thereafter). All related renewable energy purchases will be sourced from CEC-certified generating facilities, which will be eligible for use under California’s RPS Program. All of MCE’s renewable energy purchases are expected to be sourced from products meeting the delivery requirements established for PCC1.

Furthermore, MCE’s existing contractual commitments have secured the significant majority of its renewable energy requirements. Existing contracts continue to address the majority of MCE’s renewable energy needs throughout the planning period addressed in this RPS Procurement Plan and are expected to account for 97% of statutorily mandated long-term 55 renewable energy procurement requirements in 2035. MCE’s planning and procurement process remains ongoing, which is expected to result in additional renewable energy acquisition, the substantial majority of which will be secured via long-term contracts.

Additionally, MCE policy, established by MCE’s founding documents and directed on an ongoing basis by MCE’s governing board, guides development of the resource plan and related procurement activities. MCE’s key resource planning policies are as follows:
● Reduce GHG emissions and other pollutants within the electric power sector through increased use of renewable, GHG-free, and low-GHG energy resources; ● Maintain competitive electric rates and increase control over energy costs through management of a diversified resource portfolio;
● Benefit the local economy by offering competitive electricity rates and customer programs, and investing in local infrastructure, energy, and workforce-development programs within MCE’s service area;
● Help customers reduce energy consumption and electric bills by supporting and administering enhanced customer energy efficiency, cost effective distributed generation, and other demand-side programs;
● Enhance system reliability through investments in supply- and demand-side resources; ● Actively monitor and manage operating risks to promote MCE’s continued financial strength and stability; and
● Support supplier and workforce diversity as permitted by law.

MCE translates these broad policy objectives into more specific plans for the use of various types of electric resources, taking into consideration MCE’s projected customer needs and MCE’s existing resource commitments.
56 To enable MCE to meet its resource planning objectives, MCE’s governing board has formally adopted the following policies related to resource planning and procurement:
(1) MCE’s Sustainable Workforce and Diversity Policy:26 MCE is committed to supporting sustained and fairly compensated local job opportunities through participation in the energy industry. To the extent allowed by state law, MCE seeks to create market incentives and partnerships to encourage diversity and a sustainable workforce through its support for:
● Fair compensation in direct hiring, renewable development projects, customer programs, internships, and procurement services;
● Development of locally generated renewable energy within MCE’s service area; ● Direct use of union members from multiple trades;
● Quality training, apprenticeship, and pre-apprenticeship programs; ● Direct use of businesses local to MCE’s service area; ● Development of California-based job opportunities;
● Business and workforce initiatives located in low-income and disadvantaged communities;
● Direct use of Disabled Veteran-owned Business Enterprises and LGBT-owned Business Enterprises;
● Direct use of green and sustainable businesses; and
● Use of direct hiring practices that promote diversity in the workplace. (2) MCE’s Energy Risk Management Policy:27 MCE manages its energy resources and 26 See Attachment A to Agenda Item #7 from MCE’s November 16, 2017 Board Meeting, available at https://www.mcecleanenergy.org/wp-content/uploads/2020/05/MCE-Board-Meeting-Packet-November_2017.pdf. 27 See Attachment to Agenda Item #7 from MCE’s May 2, 2019, Technical Committee Meeting, 57 transactions for the purpose of providing its customers with low-cost renewable, carbon free and other energy, while at the same time minimizing risks. MCE procures energy and RA consistent with its Energy Risk Management Policy, which has been developed to ensure that MCE achieves its mission and adheres to policies established by the MCE Board of Directors, power supply and related contract commitments, good utility practice, and all applicable laws and regulations.
(ii) Responsiveness to Regional Policies
MCE is governed by a 36-member Board of Directors comprised of elected Councilmembers or Supervisors from its 38 member communities and is committed to benefiting its service area’s economy through investments in local infrastructure and energy programs.

Though several of MCE’s member communities have adopted their own climate, transportation, and/or land use goals or policies, MCE is not aware of any specific policies that require MCE to alter its resource planning or procurement practices at this time, nor is MCE aware of local or regional policies that would affect MCE’s risk of RPS compliance at this time. In part, this may be due to MCE’s voluntary renewable procurement targets that exceed state requirements and have been developed in conjunction with, and approved by, MCE’s governing board.

However, MCE is committed to abiding by all local and regional plan criteria, as adopted by (or on behalf of) its member communities. When applicable, or in the instance that any new policies are enacted by MCE member communities that may affect MCE’s resource planning process, MCE will work collaboratively with those communities to ensure continued compliance with the community, MCE, and the State policy goals.
available at https://www.mcecleanenergy.org/wp-content/uploads/2020/01/MCE-Technical-Committee-Packet-May_2019.pdf. 58 IV.D. Lessons Learned – Assessment of RPS Portfolio Supplies and Demand MCE’s operating history confirms that diversity among renewable energy commitments is highly desirable. This diversity encompasses a broad range of considerations, including the use of various fuel sources, resource locations, contract durations, product specifications, pricing mechanisms, solicitation timing and frequency, among other differences. Early-stage discipline in renewable energy contracting allowed for MCE’s solar energy commitments to gradually move down a declining cost curve, which avoided over-weighting the portfolio with an abundance of costly contracts. As California’s energy landscape continued to evolve, a concentration of renewable generating assets in certain locations reinforced the benefits of geographic diversity – as certain areas of the state were overbuilt with renewable generating infrastructure, challenges related to depressed market prices and related resource curtailments began to surface and will likely continue to exist for quite some time.28 There have also been challenges associated with transmission and deliverability of projects which can impact project viability. These observations have contributed to a more rigorous evaluation process for new generating projects, e.g., analyzing congestion patterns at specific locations, understanding the risks related to obtaining Maximum Import Capability (“MIC”) for out-of-state projects and getting more involved in the CAISO regulatory processes for transmission and interconnection to understand the risks associated with transmission and deliverability for specific projects, which is expected to reduce risks associated with such issues. While historical market pricing and transmission issues are not perfect predictors 28 It is noteworthy, however, that economic curtailment may not be feasible for certain retail sellers when considering the financial implications of long-term contract delivery shortfalls imposed under the RPS Program. Considering such significant financial charges, certain retail sellers may be forced to accept deliveries from renewable generating assets during instances of significant negative pricing to ensure that requisite long-term contracting quantities are satisfied.

This could result in higher-than-anticipated renewable energy costs and related impacts to customer rates.
59 of future performance, attempting to understand past trends helps to mitigate potential adverse financial consequences during near-term operation of such facilities. In addition, MCE analyzes anticipated project development in a geographic area as well as planned network upgrades in the CAISO’s Transmission Planning Process.

MCE has also adapted to how distinct California energy programs interact with one another. AB 1110 (stats. 2016) has devalued and, ostensibly, discouraged the use of certain renewable energy products (allowed for use under California’s RPS Program) because of how associated emissions are accounted for under the PSD Program. Changes to PSD Program regulations related to AB 1110 attribute an emissions factor equivalent to system power to any PCC2 and PCC3 volumes. In addition, PCC3 certificates are not presented as renewable purchases during power source accounting. This change has led MCE and various other CCAs to forgo or minimize the use of PCC2 and PCC3 products to avoid representing an inflated emissions factor and the potential public/customer perception that reported renewable energy content is lower than required under California’s RPS Program or related policy commitments of the retail seller. This adaptation to MCE’s planning and procurement practice became necessary even though such products are deemed eligible for use under California’s RPS Program. As such MCE will endeavor to source all renewable energy purchases from PCC1 products but may, in isolated instances, procure small quantities of PCC2 products when unanticipated renewable energy delivery shortfalls, higher than expected retail sales and/or prevailing market conditions necessitate such purchases. Exhibiting strong preferences for PCC1 products is expected to increase costs and customer rates but will promote MCE’s achievement of emission-related portfolio objectives. 60 V. Project Development Status Update
As described in Section IV.B above, MCE’s current and planned procurement is sufficient to meet both the applicable RPS procurement requirements as well as support the state’s GHG reduction targets. Further, MCE’s current and planned procurement supports system reliability by considering portfolio diversity, mid-term reliability requirements, and alignment with MCE customers’ load curve.

As of this filing, MCE has entered into three long term contracts with utility-scale RPS-eligible resources that are not yet commercially operational, each of which is a large utility-scale project. MCE also has long term PPAs for deliveries from three smaller renewable projects, less than 5 MWs, that were selected through MCE’s Feed-In-Tariff (“FIT”) program or DAC-GT Program – all of which are in development.The following Table 7 shows a list of the most recent projects added to MCE’s portfolio that MCE is using for RPS and/or IRP purposes to support MTR requirements, RPS, and IRP reliability and emissions goals. Each of the projects listed below are either in development or have come online in the last two years to support MCE RPS and IRP-related needs.
61 There are also several smaller scale projects with contract capacities below 5 MWs.

MCE has updated the RNS template and the Cost Quantification templates to reflect projects listed in Table 7 below.29 MCE intends to keep the Commission informed of the progress on these projects through the various monthly and quarterly reports on project status. 29 The RNS template includes each of the resources in Table 7, with the exception of any stand-alone battery storage resources as they are not RPS eligible. However, MCE lists them in Table 7 below as they are otherwise procured as part of MCE’s larger procurement strategy. 62 Table 7: MCE Project Development Status
Facility Name Technology
Type
MW-ac MTR
Project
Location
(County in CA)
COD Length
of
Contract
(Years)
Network
Upgrades
Milestone
Daggett Solar Solar +
Storage
110
PV/60
Storage
Yes San Bernadino 8/25/2023 15 Completed
Golden Fields
Solar IV, LLC
Solar +
Storage
100
PV/92
Storage
Yes Kern 8/16/2025 15 Completed
Strauss Wind
Project
Wind 93.35 Yes Santa Barbara 12/20/2023 15 Completed
Humboldt
House
Geothermal 20 Yes Pershing, NV 2028
(anticipated
)
21 In Progress
Geysers
(7MW)
Geothermal 7 Yes Sonoma 6/1/2025 20 Completed
Key30 8-Hour
Battery
Storage
35 Yes Fresno 6/1/2027 15 Completed
Cormorant31 Battery
Storage
188 Yes San Mateo 6/1/2026 15 Completed
Corby32 Battery
Storage
100 Yes Solano 4/1/2027 15 Delayed
Allium Hybrid Solar +
Storage
110
PV/110
Storage
San Benito 5/1/2031 20 In progress
Conflitti Solar 4.4 No Fresno 3/31/2026 20 In progress
Conflitti Jr. Solar .24 No Fresno 3/31/2026 20 In progress Fallon Two
Rock Rd Solar
Farm
Solar 0.96 No Marin 1/29/2024 20 Completed
Ranch Sereno Solar 2 PV/.8
Storage
No Fresno 12/31/2025 20 In progress
63 MCE’s Large Scale Projects
There are a total of nine large scale new build projects with contract capacities between 7 MWs at the lower bound and a combined 110 MW Solar/188 MW Storage at the upper bound, which includes six RPS-eligible projects and three non-RPS-eligible projects. The six RPS-eligible, projects are expected to produce approximately 1,463,560 MWh annually of RPS eligible energy. Three of the projects (Daggett Solar, Strauss Wind Project and Geysers) have already achieved commercial operation, while the remaining three renewable projects are in development. MCE plans to use all nine of these projects towards its IRP-related procurement needs.

MCE’s Feed-In-Tariff projects
MCE’s FIT program allows developers to finance local renewable energy projects, while catalyzing local job creation associated with the construction, operation, and maintenance of these local projects.33 By providing attractive, above market rates, this program incentivizes renewable development in MCE communities where it otherwise would not be built. To date, MCE’s FIT program has supported the completion of twenty-four locally situated, small scale renewable generating projects, which are currently producing electricity that is purchased by MCE under long-term contracts. One FIT project is currently under development as of the date 30 This is a stand-alone battery storage project that is not RPS-eligible. This resource is being provided to demonstrate additional, non-RPS MCE procurement that is in alignment with IRP needs.
31 This is a stand-alone battery storage project that is not RPS-eligible. This resource is being provided to demonstrate additional, non-RPS MCE procurement that is in alignment with IRP needs.
32 This is a stand-alone battery storage project that is not RPS-eligible. This resource is being provided to demonstrate additional, non-RPS MCE procurement that is in alignment with IRP needs.
33 See https://www.mcecleanenergy.org/feed-in-tariff/.
64 of this filing.

MCE has also attached an updated version of the Project Development Status Update Report as Appendix D.

VI. Potential Compliance Delays
MCE has received favorable determinations of compliance relating to Compliance Period 1, Compliance Period 2, and Compliance Period 3, which indicate that “MCE met its RPS compliance obligations” during such periods. MCE expects similar determinations related to Compliance Period 4, which includes calendar years 2021-2024, as well as future compliance periods. This perspective is based on MCE’s past success in meeting RPS compliance mandates as well as MCE’s internally adopted, above-RPS renewable energy targets and procurement activities as well as actual renewable energy deliveries and projections, which seem to indicate the organization is tracking well ahead of schedule in satisfying applicable RPS mandates.

Regarding long-term contracting compliance, and as discussed above, MCE has secured long-term contract commitments sufficient to meet the noted requirements throughout the planning period, even in the event of potential delivery shortfalls equivalent to MCE’s adopted MMoP.

VII. Risk Assessment
MCE closely monitors development and operational risks associated with its planned and existing renewable energy supply commitments to minimize the potential for significant variances between actual and expected renewable energy deliveries.

VII.A. Compliance Risk
An important element of MCE's RPS risk assessment process is determining potential vulnerabilities related to procurement and/or delivery shortfalls that could trigger deficits relative 65 to MCE’s anticipated compliance obligations. Considering MCE’s internally adopted renewable energy procurement targets and existing contractual commitments, this risk, as internally determined by MCE, appears to be very low. As discussed throughout this plan, MCE has established a Voluntary Margin of Over-Procurement (“VMoP”) and, further, a MMoP that inform RPS procurement efforts and ensure against compliance-related shortfalls. If there is any change in terms of MCE’s internal assessment of RPS compliance risk, MCE will inform the CPUC accordingly in a future RPS Procurement Plan.

VII.B. Risk Modeling and Risk Factors
MCE has established a Risk Oversight Committee (“ROC”), which regularly convenes to discuss conformance of MCE’s ongoing planning and procurement efforts with the organization’s adopted Energy Risk Management Policy (“ERM Policy”). MCE’s ERM Policy was developed for purpose of creating and maintaining controls and processes that will mitigate potential exposure to various sources of risk, including market price risk, counterparty credit and performance risk, load and generation (volumetric) risk, operational risk, liquidity risk and policy (e.g., legislative and regulatory) risk.

To the extent that higher-than-expected renewable energy open positions, counterparty over-exposure, meaningful load variations or other pertinent planning observations are identified during meetings of the ROC, MCE adjusts procurement activities to address these concerns, which promotes ongoing compliance with its ERM Policy. Should any significant ERM Policy deviations be identified, MCE staff would inform its Governing Board before pursuing corrective action.

MCE’s risk assessment and management practices are described in greater detail below.

In general terms, MCE’s process for minimizing and avoiding risk is deterministic in nature and begins with the development of bid requirements and evaluative preferences for 66 solicitations. MCE’s solicitations are intended to identify suppliers that have demonstrated a strong track record of successful project completion and ongoing project operation. Such counterparties are more likely to timely complete project development activities and successfully operate projects placed under contract, and therefore minimize project risks. This process has yielded strong results: the pool of responses to MCE-administered solicitation is generally robust; the quality of short-listed respondents is high and typically includes very experienced bidders with strong project development track records; the short-listed candidates, by virtue of their considerable project development and/or operational experience, tend to be efficient contract negotiators; and the resulting contracts have generally led to project deliveries that meet MCE’s expectations.

Key risk factors are considered during evaluation of each prospective renewable energy seller, including counterparty credit rating and general financial standing; California-based project development experience; prior experience with CCA off-takers; commercial viability of the proposed generating technology; and progress towards key development milestones such as interconnection status, deliverability studies, siting, zoning, permitting, and financing requirements. With regard to transmission adequacy, MCE ensures that each project has an executed interconnection agreement with the appropriate participating transmission operator prior to contract execution so that the project's interconnection costs, deliverability and timelines are known to the extent possible. MCE also conducts a review of interconnection queues and transmission planning in the area to understand impacts of planned projects and transmission upgrades. The project review process also includes a thorough review of the permitting status from the permitting authority and must demonstrate a path to completion. A selected seller bears risk of supply chain delays impacting the seller’s ability to meet its guaranteed contractual milestones on 67 time, subject to permitted extensions and allowable Force Majeure provisions in the contract.

To the extent that a prospective renewable energy procurement opportunity comes to fruition, and a contract is executed, development milestones are rigorously monitored by MCE’s contract management staff, who regularly communicate with the project sponsor throughout the development and construction processes.

MCE also seeks to minimize unnecessary financial exposure and general planning risk by assembling a diversified portfolio of renewable generating resources and products that are intended to complement the way its customers use electric power. To promote this alignment of supply and demand, MCE analyzes the impacts of proposed renewable energy deliveries to its aggregate resource portfolio relative to expected customer energy use as part of its evaluation process. To the extent that the proposed delivery profile would create undesirable net-short or net-long positions, alternative product options will continue to be evaluated. MCE may also pursue contract structures that promote volumetric stability through firm delivery quantities and/or performance guarantees that provide for financial remedies/penalties in the event of delivery shortfalls. If necessary, the financial remedies received by MCE could be used to: (1) as a first priority, procure additional renewable energy supply to address delivery shortfalls; or (2) in the event that the delivery shortfall caused MCE to be found non-compliant, offset the cost of related penalties. MCE’s intent is to exceed compliance with applicable RPS mandates, and the latter option is a last resort that is not expected to apply.

While attempts to “time the market” may occasionally yield short-lived benefits, such results are generally not reliable and create the potential for significant risk and financial consequences if market conditions quickly and/or significantly change. MCE’s deliberate contracting approach entails “sampling” the market at regular intervals, avoiding large contractual commitments in high-priced environments or missed opportunities in low-priced environments.

MCE also ensures that its contract start/end dates and related term lengths are staggered to avoid planning “cliffs” that could occur if contracts of similar lengths and start dates were all executed at the same time. The assembly of short-, medium- and long-term contracts further diversifies risk within MCE’s renewable supply portfolio, and while increased long-term RPS contracting requirements will inevitably increase such risks, MCE will continue to pursue portfolio diversity by thoughtfully considering these temporal considerations during ongoing procurement processes.

MCE utilizes a quantitative risk assessment that evaluates the energy impacts related to supply side losses. This approach organizes prospective risks into three general categories which pose the greatest supply-side impacts to the delivery of expected RPS energy: 1) curtailment risk; 2) resource intermittency risk; 3) counterparty risk; and 4) project cancellation risk. As part of its quantitative risk assessment, MCE examines hourly forward-looking price data and historical CAISO data to quantify curtailment risk. Considering MCE’s current long-term renewable energy positions that are well in excess of requirements, a reduction in long-term RPS volumes due to curtailment is unlikely to compromise the prospect of RPS compliance. The figures presented in the column quantifying curtailment risk in Table 8 at the end of this section are calculated by 69 quantifying the volume of energy deliveries expected to occur during the balance of each contract’s respective delivery period. This volume is then multiplied by the likelihood of curtailment (expressed as a proportionate reduction in total deliveries), which varies by contract in consideration of MCE’s historical observations related to generator performance and expected performance in the future. In consideration of the increased curtailment of wind and solar resources within CAISO over the past several years, MCE has assumed a minimum baseline curtailment adjustment for certain contracts within its portfolio that may be curtailed in consideration of prospective negative price risk. Based on MCE’s assessment of curtailment risk associated with its renewable energy contract portfolio, this risk category was assigned a rating of medium. When compared to the similar categorical risk assessment presented in MCE’s 2024 RPS Procurement, this risk rating remains unchanged.

Intermittency risk has become increasingly prevalent in the wake of ongoing renewable infrastructure buildout. In particular, California’s substantial reliance on photovoltaic solar and wind generating facilities introduces intermittency risk for any retail seller procuring power from such projects. Such risks ought to be accounted for as part of a thoughtful quantitative risk assessment to ensure the identification of sufficient planning reserves. The following describes MCE’s methodology for assessing intermittency risk. As new intermittent facilities are developed to meet the procurement burdens of increasing regulatory requirements, the risk of variances between projected and actual energy deliveries is amplified. Quantifying intermittency risk is largely dependent on available data, as each generating facility is unique (geographically, operationally, etc.). As data is gathered from facilities comprising an RPS supply portfolio, planning adjustments can be incorporated to account for variances between actual and expected historical deliveries, allowing the retail seller to incorporate adjustments in its resource planning 70 and procurement assumptions to counteract such risk. During the early stages of any delivery period, however, data is often lacking so planning adjustments are more challenging to quantify and must be based on reasonable estimates derived by observing similar projects. Over time, as meaningful amounts of historical data are compiled, MCE should be able to make increasingly accurate adjustments to its planning assumptions to ensure that procured RPS volumes are more accurately aligned with anticipated needs.

Despite these challenges, MCE believes that intermittency risk can be reasonably quantified when available operating history reaches two years or more. Before substantive historical data becomes available, other information must be considered in assessing intermittency risk, including input from the asset owner/operator, insight derived from the operating history associated with similar generating facilities, and limited historical data (that can be applied to generate interim intermittency assessments). Once a generating facility has established steady-state operations, intermittency risk can be quantified by dividing the amount of actual energy received by the amount of expected energy for each year of a given contract, then averaging observed variances across each year of the available operating history. The resulting percentage is multiplied by the remaining expected energy deliveries under the contract to approximate potential delivery deficits related to intermittency. For facilities with limited operating history and/or facilities that have yet to achieve commercial operation, MCE imputes proxy intermittency adjustments to ensure conservatism in RPS planning assumptions. For example, if MCE’s experience with smaller-scale photovoltaic solar generating facilities (e.g., facilities at or below 10 MW of nameplate capacity) suggests that actual generation typically falls within negative two percent of projections, MCE will apply a negative two percent intermittency adjustment to generating facilities falling within this category. Similarly, if MCE has observed that mid-sized 71 wind generating facilities (e.g., wind generating facilities between 20 and 100 MW of nameplate capacity) occasionally produce ten percent less energy than projected in certain calendar years, it will apply a negative ten percent intermittency adjustments to generating facilities within this category. Again, this approach promotes a conservative RPS planning process and should avoid unexpected delivery shortfalls related to resource variability for intermittent generating sources.

Employing this intermittency analysis is also helpful in identifying especially risky contracts, which in turn assists MCE in determining which facilities must be closely monitored throughout the contract delivery term. As alluded to above, as more data becomes available, intermittency risk metrics can be updated to more accurately reflect the performance of certain generating facilities over time. Based on MCE’s assessment of intermittency risk associated with its renewable energy contract portfolio, this risk category was assigned a rating of low. MCE believes that its MMoP serves as an important mitigating strategy in addressing potential delivery shortfalls related to resource intermittency. MCE also notes that its VMoP, which significantly exceeds applicable RPS procurement mandates, serves as mitigating mechanism for any compliance risk related to resource intermittency as typical intermittency levels fall well below MCE’s VMoP.

Counterparty risk is the risk posed by a counterparty being unable or unwilling to honor its total RPS delivery obligations, as reflected in related contract documents. MCE has quantified this likelihood by considering S&P Global’s Global Corporate Annual Default Rates by Rating Category (%) as a measure of organizational viability and financial stability. While this rate considers industries beyond the energy sector, it provides relevant insights into the correlation and potential impacts of dealing with uncreditworthy counterparties. The likelihood of default by credit rating was averaged over the years from 2014 to 2019. These years were chosen to remove irregularities in default rates during the Covid-19 pandemic; though no material impacts to MCE’s 72 risk assessment are anticipated, MCE expects to update the time period associated with its default by credit rating assessment during completion of the 2026 planning process and may shift the aforementioned time period forward to include other/additional years. If a counterparty was found to be unrated, then the contract was reviewed to identify specified credit assurances; based on such assurances, an approximate rating was derived based on MCE’s experience and risk tolerance.

Based on MCE’s assessment of counterparty risk associated with its renewable energy contract portfolio, this risk category was assigned a rating of low. The final category reflected in MCE’s analysis is project/contract cancellation risk. This category is distinct from counterparty risk because the risk of project/contract cancellation may only affect a single project under a counterparty’s portfolio. Projects may be cancelled for a variety of reasons, but in today’s market, deals struck many months ago may no longer be economic for the seller. This risk only effects single source projects which have yet to be constructed. These projects were chosen because they have a single point of failure unlike RPS energy purchased from a pool of resources (under a portfolio-style purchase agreement in which there is generally more diversity amongst the sources of supply). Based on discussions with various counterparties, other load serving entities and its own experience, MCE has assessed that this risk affects roughly 1 in 20 deals (with such circumstances generally applying to less experienced and/or reputable suppliers). Based on MCE’s assessment of project/contract cancellation risk associated with its renewable energy contract portfolio, and the high-quality counterparties which comprise MCE’s list of suppliers, this risk category was assigned a rating of low.

Considering these categories holistically, MCE was able to derive a cumulative energy percentage at risk. In consideration of MCE’s relatively conservative risk tolerances, a top-level risk of non-delivery offset at 0.25% of renewable energy procurements was added to the calculated 73 energy at risk percentage. This adder will help to account for risks that MCE cannot foresee and will help to guarantee the sufficiency of MCE’s planned RPS purchases in meeting both compliance-related and internally adopted renewable energy procurement targets. The percentage of renewable energy and error is the percentage of total renewable energy procured that was determined to be at risk, while the percentage of retail load is the energy at risk as a percentage of retail load. These “at risk” percentages reflect possible losses which, through no fault of MCE, may occur by virtue of being a market participant. These losses pose a risk for non-compliance relative to MCE’s RPS goals and targets. Since this number is not a guaranteed loss, MCE will implement the previously mentioned mitigation strategies to give the greatest chance of meeting its adopted renewable energy procurement targets.

Table 8: MCE Contract Curtailment, Counterparty, and Project Cancellation Risk Delivery & Market Risks
ID Contract
Energy to be
Delivered to
Market
(MWh)
Curtailment
Risk (MWh)
Counterparty
Risk (MWh)
Intermittency
Risk (MWh)
Project
Cancellation
Risk (MWh)
7 Contract
342 906,989 36,280 9,070 90,699 -
8 Contract
343 386,291 15,452 3,863 - -
9 Contract
491 3,463,882 138,555 34,639 346,388 -
10 Contract
492 24,219 969 242 484 -
11 Contract
494 5,857 234 59 117 -
12 Contract
496 3,144,948 125,798 31,449 314,495 -
13 Contract
497 21,275 851 213 425 -
14 Contract
498 21,275 851 213 425 -
15 Contract
499 2,318,298 92,732 23,183 46,366 -
74 16
Contract
500 1,317,030 263,406 13,170 26,341
-
17 Contract
501 426,286 85,257 4,263 8,526
-
18 Contract
502 722,066 144,413 7,221 14,441
-
19 Contract
503 2,039,327 407,865 20,393 40,787
-
20 Contract
505 12,980 519 130 260
-
21 Contract
507 522,652 20,906 5,227 52,265
-
22 Contract
586 123,100
- 1,231 2,462-
23 Contract
853 41,495 1,660 415 830
-
24 Contract
855 41,495 1,660 415 830
-
25 Contract
856 38,926 1,557 389 779
-
26 Contract
886 38,926 1,557 389 779
-
27 Contract
887 38,926 1,557 389 779
-
28 Contract
1001 40,444 1,618 404 809
-
29 Contract
1002 40,444 1,618 404 809
-
30 Contract
1035 31,978 1,279 320 640
-
31 Contract
1068 460 18
59-
32 Contract
1070 22,332 893 223 447
-
33 Contract
1071 460 18
59-
34 Contract
1679 349,077 13,963 3,491 6,982
-
35 Contract
1680 480,134 19,205 4,801 9,603
-
36 Contract
1681 37,022 1,481 370 740
-
37 Contract
1685 228,914 9,157 2,289 4,578
-
38 Contract
1686 50,576 2,023 506 1,012
-
75 39
Contract
1746 427,831 17,113 4,278 42,783
-
40 Contract
1955 40,444 1,618 404 809
-
42 Contract
2131 220,372 8,815 2,204 4,407
-
43 Contract
2440 3,275,754 131,030 32,758 65,515
-
44 Contract
2475 47,820 1,913 478 4,782
-
45 Contract
2522 28,594 1,144 286 572
-
46 Contract
3548 36,159 1,446 362 723
-
47 Contract
3549 238,194 9,528 2,382
--
48 Contract
3550 19,431 777 194
--
49 Contract
3584 26,790 1,072 268
--
50 Contract
3585 188,631 7,545 1,886 3,773
-
51 Contract
3706 4,644,435 185,777 46,444 92,889
-
52 Contract
3710 298,982 11,959 2,990 5,980
-
53 Contract
3720 103,114 4,125 1,031
--
54 Contract
3735 12,781 511 128 256
-
55 Contract
3736 234,535 9,381 2,345 4,691
-
56 Contract
3749 4,335,021 173,401 6,069
--
58 Contract
3864 1,121,700 44,868 11,217
--
59 Contract
3867 3,264,963 130,599 32,650 65,299
-
61 Contract
3877 8,766,200 350,648 87,662 175,324
-
62 Contract
3878 1,227,100 49,084 12,271 24,542
-
64 Contract
3892 2,754,702 110,188 27,547
--
65 Contract
3926 403,557
- 4,036 8,071-
76 69
Contract
3958 100,000 - 1,000 - -
70 Contract
3959 100,000 - 1,000 - -
75 Contract
4007 500,000 - 590 - -
76 Contract
4015 100,000 - 1,000 - -
77 Contract
4021 50,000 - 500 - -
78 Contract
4022 55,000 - 65 - -
79 Contract
4030 700,000 - 7,000 - -
80 Contract
4052 100,000 - 1,000 - -
81 Contract
4056 350,000 - - - -
82 Contract
4057 450,000 - 531 - -
83 Contract
4058 200,000 - 2,000 - -
84 Contract
4059 100,000 - 1,000 - -
85 Contract
4062 5,152,517 206,101 - 103,050 -
86 Contract
4063 477,749 19,110 4,777 9,555 -
87 Contract
4065 200,000 - 2,000 - -
Total
Energy 57,290,461 2,871,106 471,734 1,587,134 -
Total Renewable Energy
57,290,461
Total Renewable Energy at Risk 4,929,974
% of Renewable Energy at Risk 8.61%
% of Unknown Error at Risk

0.25%
% of Renewable Energy & Error at
Risk 8.86%
% of Retail Load

7.91%
77 Based on MCE’s updated risk assessment, MCE determined that approximately 8.6 percent of MCE’s expected future RPS deliveries may be at risk, which equates to 7.9 percent of MCE’s retail load during the current planning period – MCE notes that the 7.9 percent (relative to retail load) risk statistic falls between MCE’s near-term MMoP of 6 percent, which applies through 2025, and the 8.5 percent MMoP, which applies in 2029 and beyond. This suggests that MCE’s MMoP is appropriately set in consideration of its existing RPS supply portfolio. The noted percentages reflect average risk throughout the study period, which suggests that actual risk could fall somewhat above or below these percentages. Regardless, the potential risk-related impacts to MCE’s RPS supply portfolio align well with MCE’s MMoP trajectory, as reflected in this RPS planning process. In consideration of the results of MCE’s risk analysis, the composite risk assessment, which considers all four of the previously described risk categories, results in an overall risk rating of low.

MCE’s rigorous process for evaluating prospective suppliers continues to be successful in identifying highly qualified, financially viable candidates and supporting its achievement of both statutory and voluntary renewable energy procurement goals. MCE will continue to evaluate the usefulness of other risk assessment tools as it moves forward. Should MCE identify compliance-related concerns through application of its ERM Policy, recently completed risk assessment or other mechanisms, MCE will take the appropriate course of action, which may include additional or enhanced quantitative risk assessments or other planning studies, to address such issues before compliance is affected.

VII.C. Lessons Learned – Risk Assessment
In terms of lessons learned related to risk management, MCE has observed that “more is generally better” when it comes to procuring renewable energy to satisfy RPS compliance 78 obligations. And while this approach may not be a viable or desirable option for all retail sellers, it has served MCE well. More specifically, MCE’s 60% renewable energy commitment (which gradually increases to 85% in 2031) has positioned the organization with substantial RPS planning reserves and minimal compliance risk. Since the 60% renewable energy commitment became effective in 2017, the risks faced by MCE have transitioned away from compliance-related concerns in favor of broader integrated resource planning initiatives. MCE is now focused on identifying resources that are not only cost-effective, but complementary to its existing portfolio of renewable energy supply contracts and projected customer energy use. As the level of renewable energy increases within MCE’s portfolio, MCE has observed that the scope of resources promoting alignment between supply and demand generally becomes narrower and more costly.

In recent years, MCE has also experienced significant impacts of the MTR compliance mandate on the market for energy storage and renewable energy. The MTR compliance mandates34 require LSEs across California to bring 15,500 MW of incremental NQC capacity online in phases by 2028. The mandates further define the required characteristics for the new resources that, in some instances, restrict the new construction to specific technologies. Given the compliance mandates and market conditions such as labor shortages, increased equipment costs, and delayed deliveries of key components, buyers have seen significantly higher prices and been forced to take higher risk than normal on their long-term contracts in order to bring these resources online in time to meet the compliance requirements. As a result, developers are passing through unprecedented price increases to LSEs for new and existing contracts. While scenarios such as this are difficult to prepare for, one key takeaway is that timely planning and forecasting at the state level is key to building a reliable and affordable grid. Additionally, MCE is managing these risks by working on 34 Please see section on MTR compliance mandate.
79 backup plans with the developers in case there are unforeseen events, while still minimizing their impact on ratepayers.

There is also concern related to the management of long-term renewable supply commitments that exist within geographic areas where negative price risk and related curtailment of energy production has become increasingly prominent. This risk is becoming more challenging to manage as California’s escalating RPS procurement mandates necessitate ongoing investment in new renewable generating infrastructure, which is often sited in resource-rich areas that become oversaturated with similar generating technologies. These circumstances seem inevitable and, over the course of a long-term supply relationship, may expose the contracted parties to unexpected risks, including negative prices (and related budgetary impacts) and curtailed deliveries which may compromise the fulfillment of mandated procurement targets by the buyer. However, MCE’s internally adopted, above-RPS renewable procurement targets allow flexibility if/when curtailment becomes necessary, or when contracted renewable resources underperform.

In terms of MCE’s contracting process, MCE has also learned that diversified sharing of risk within a renewable contract portfolio is desirable. There are many different contract structures, all of which serve a valuable purpose, which can be employed to create the desired allocation of risk between buyers and sellers. For example, an “index-plus” pricing structure is useful in transferring nodal price risk to the seller. In such structures, the buyer pays a fixed renewable premium, while the seller assumes risk associated with market price fluctuations but also receives market revenues – even though the buyer receives the energy, renewable attribute and, in certain instances, capacity value as part of such a transaction, the buyer’s financial risk is generally limited to the payment of the renewable premium. For buyers who are averse to market price risk, the index-plus pricing structure effectively eliminates this concern but may result in a higher overall 80 contract cost, which may be acceptable as a form of insurance, to mitigate market price exposure.

In other structures, such as the “fixed-price” or “aggregate pricing” structure, the renewable energy premium and energy commodity (and oftentimes, capacity value) are reflected in a single price paid by the buyer – this structure deliberately allocates market price risk to the buyer, but the buyer may also pay a lower imputed renewable premium in instances where market revenues closely approximate, or exceed, the aggregate renewable energy price.

In considering potential contract structures, decisions are ultimately made in consideration of risk allocation preferences, and MCE has found that it is generally desirable to pursue broad diversity in renewable energy contracting, inclusive of resource location, generating technology, suppliers/developers, and contract structures, amongst other considerations. MCE acknowledges, however, that newer retail sellers that have yet to establish meaningful financial reserves or cost-conscious retail sellers, who may be working to suppress power supply costs in consideration of a cost-sensitive customer base, may choose to favor arrangements that allocate market price risk to sellers/suppliers, particularly during early-stage operations.

Finally, MCE has learned that every CCA is different and that there is no pre-determined risk management methodology or procurement approach that is without challenges. Pursuing resource diversity across a broad spectrum of planning considerations over the long-term planning horizon appears to be one of the most viable mechanisms in mitigating RPS compliance risk.

VIII. Renewable Net Short Calculations
MCE’s failure rate for new-build renewable generation placed under contract is well below five percent. MCE takes several steps to guard against the risk of project failure, including:
● Pre-contracting diligence, including a rigorous proposal evaluation process. MCE requires that any new-build project be in an advanced stage of the pre-development process, 81 including permitting, financing, and interconnection. In particular, MCE’s practice is to execute a PPA only after a project’s interconnection agreement is fully executed. This increases certainty with regard to the project’s development timeline and costs. ● Project monitoring, MCE’s PPAs for new-build projects require frequent, detailed progress reports, which helps to identify and mitigate potential problems in their early stages. ● Internal renewable portfolio targets, including a planning reserve, that meaningfully exceed statewide mandates.

MCE has increased its planned RPS procurement to account for expected delivery shortfalls and consults its periodically updated quantitative risk assessment to determine whether further adjustments are needed to its future planning assumptions. Based on its most recently updated quantitative risk assessment, MCE determined that approximately 7.9 percent of future deliveries are at risk during the current planning period, based on projected retail load within the planning period (this failure rate equates to 8.6 percent of projected future RPS deliveries; MCE has rounded this up to 10 percent within Appendix C). These adjustments were primarily made to address: 1) generalized planning conservatism to ensure the sufficiency of MCE’s RPS supply relative to its relatively high, internally adopted procurement targets, 2) occasional curtailment of select in-state renewable generating facilities due to negative pricing at certain times of the year; and 3) intermittency risk associated with certain renewable generating technologies, such as those using solar and wind as fuel sources. MCE continues to use actual planning data as compared to its forecast throughout the year and can adjust to supply- or demand-side variations within a given year.

MCE has provided a quantitative assessment to support the qualitative descriptions provided in this RPS Procurement Plan, which is attached as Appendix C. As previously noted, 82 MCE has successfully procured more than 60% of its resource needs from RPS-eligible renewable resources since 2017 and, as a result, has accrued renewable energy well in excess of applicable statewide mandates. With few exceptions, renewable suppliers have performed as expected, so the noted failure rates that are reflected in Exhibit C are well in excess of the findings reflected in MCE’s previously described risk assessment, which indicate that just over two percent of such supply may be at risk. If supplier performance becomes more erratic in the future and such adjustments are deemed necessary, MCE will reflect such adjustments in a future planning document.

IX. Minimum Margin of Procurement
IX.A MMoP Level
MCE is developing an electricity supply portfolio that will further the achievement of state mandates, as well as internally adopted goals, for increasing RPS-eligible renewable energy supply over time. The following table displays MCE’s intended margin of RPS over-procurement based on the differential between the SB 100 procurement targets and MCE’s internally adopted RPS procurement targets. This table reflects MCE’s voluntary margin of over-procurement, or VMoP.

Table 9: MCE Voluntary Margin of Over-Procurement
SB 100 RPS
Procurement
Requirement (% of
Retail Sales)
MCE’s Internally Adopted
RPS Procurement Target
(% of Retail Sales)
MCE’s Voluntary Margin
of Over-Procurement (%
of Retail Sales)
2025 46.7% 60.0% 13.3%
2026 49.3% 60.0% 10.7%
2027 52.0% 65.0% 13.0%
2028 54.7% 70.0% 15.3%
83 2029 57.3% 75.0% 17.7%
2030 60.0% 80.0% 20.0%
2031 60.0% 85.0% 25.0%
2032 60.0% 85.0% 25.0%
2033 60.0% 85.0% 25.0%
2034 60.0% 85.0% 25.0%
2035 60.0% 85.0% 25.0%
As reflected in Table 9, MCE’s RPS-eligible renewable energy target is currently set at 60 percent through 2026, increasing to 85 percent by 2031. MCE’s internally adopted renewable energy procurement targets are intended to support MCE’s broader goal of providing a 95 percent carbon-free electricity to all customers, beginning in 2024, with increasing proportions of renewable energy over time. MCE’s internally adopted renewable energy procurement goals ensure a significant margin of procurement above the SB 100 mandates. Further, MCE’s internally adopted renewable energy procurement mandates provide a meaningful buffer above the state’s RPS requirements and serves as MCE’s VMoP. As shown in Table 9, MCE’s VMoP will minimally exceed statewide RPS mandates by at least 10.7 percent, relative to retail sales, throughout the planning period.

To address RPS compliance risk, MCE uses its risk assessments, including its renewable net short calculations, to establish a Minimum Margin of Over-Procurement (MMoP) to guide RPS compliance planning. MCE calculated the MMoP by applying a 10 percent risk adjustment (or planning reserve) to the entirety of MCE’s projected Light Green renewable energy requirements. Light Green is MCE’s default retail service option, which establishes the renewable energy percentage provided to all MCE customers. On a voluntary basis, MCE customers may 84 enroll in one of MCE’s 100 percent renewable energy service offerings: Deep Green or Local Sol.35,36 Based on the way MCE has established its MMoP, the effective MMoP percentages observed by MCE throughout the planning period range from 12.2 percent in 2026, to 14.2 percent beginning in 2031, relative to MCE’s projected RPS compliance need. MCE’s MMoP is intended to address potential delivery variability for intermittent resources, curtailment risk, project delays or failures and other operational peculiarities that may cause actual renewable energy deliveries to deviate from projections. The table below provides additional detail regarding the effective MMoP percentages observed by MCE.

Table 10: MCE Minimum Margin of Over-Procurement
SB 100 RPS
Procurement
Requirement
(% of Retail
Sales)
MCE’s
Internally
Adopted RPS
Procurement
Target (% of
Retail Sales)
MCE’s RPS
Planning
Risk
Adjustment
(at 10% of
Internally
Adopted
RPS Target)
MCE’s
Minimum
Margin of
Over-Procurement
(% of Retail
Sales)
MCE’s
Minimum
Margin of
Over-Procurement
(% buffer
relative to
RPS
Mandate)
2025 46.7% 60.0% 10.0% 6.0% 12.9%
2026 49.3% 60.0% 10.0% 6.0% 12.2%
2027 52.0% 65.0% 10.0% 6.5% 12.5%
2028 54.7% 70.0% 10.0% 7.0% 12.8%
2029 57.3% 75.0% 10.0% 7.5% 13.1%
2030 60.0% 80.0% 10.0% 8.0% 13.3%
2031 60.0% 85.0% 10.0% 8.5% 14.2%
35 See https://www.mcecleanenergy.org/100-renewable/.
36 See https://www.mcecleanenergy.org/100-local-solar/. 85 2032 60.0% 85.0% 10.0% 8.5% 14.2%
2033 60.0% 85.0% 10.0% 8.5% 14.2%
2034 60.0% 85.0% 10.0% 8.5% 14.2%
2035 60.0% 85.0% 10.0% 8.5% 14.2%
IX.A.1. MMoP Methodology and Inputs
MCE’s MMoP is intended to address an RPS failure similar to that which is reflected in the RNS template. In the event of substantial under-deliveries, commercial operation delays and/or project failure, the MMoP should be sufficient to ensure MCE is compliant with the RPS procurement requirements. MCE’s VMoP is the annual RPS-eligible minimum portfolio content identified in MCE’s internally adopted planning targets.

As discussed in Section VII, MCE has incorporated risk adjustments to certain renewable energy delivery estimates associated with existing generation. Incorporated risks include:
increased fire risk throughout the state of California, the potential for related delivery reductions, delivery intermittency, and resources that are under development. Achieving MCE’s MMoP requires levels of renewable energy procurement, ranging from 12.2 percent to 14.2 percent (throughout the planning period), above MCE’s annual RPS compliance need. This additional renewable energy procurement accommodates potential delivery shortfalls due to a variety of circumstances while still allowing MCE to meet prescribed RPS mandates.

When considered in concert, MCE’s VMoP and MMoP provide a substantial renewable energy planning buffer, relative to applicable compliance mandates, as reflected in the table below.
86 Table 11: MCE’s VMoP and MMoP
SB 100 RPS
Procurement
Requirement
(% of Retail
Sales)
MCE’s Internally
Adopted RPS
Procurement Target
(% of Retail Sales)
MCE’s Voluntary
Margin of Over-Procurement (% of
Retail Sales)
MCE’s Minimum
Margin of Over-Procurement (%
of Retail Sales)
2025 46.7% 60.0% 13.3% 6.0%
2026 49.3% 60.0% 10.7% 6.0%
2027 52.0% 65.0% 13.0% 6.5%
2028 54.7% 70.0% 15.3% 7.0%
2029 57.3% 75.0% 17.7% 7.5%
2030 60.0% 80.0% 20.0% 8.0%
2031 60.0% 85.0% 25.0% 8.5%
2032 60.0% 85.0% 25.0% 8.5%
2033 60.0% 85.0% 25.0% 8.5%
2034 60.0% 85.0% 25.0% 8.5%
2035 60.0% 85.0% 25.0% 8.5%
Since it began serving customers in 2010, MCE has consistently exceeded the state’s RPS requirements, as reflected in the chart below. Note that MCE’s reported Light Green renewable content in 2024, as reflected in its recently submitted Power Source Disclosure Report, was 70.9%. MCE will continue updating this chart in future planning documents. 87 Figure 3: MCE RPS Progress Relative to Statewide Mandates IX.A.2. MMoP and VMoP Scenarios
MCE plans to meet the annual program renewable goals reflected in the table presented in Section IX (above), including the MMoPs reflected therein. As reflected in this table, MCE’s anticipated MMoP percentages range from 6.0 percent in 2025 to 8.5 percent in 2035. MCE’s RPS Procurement Targets, as well as the renewable net short reflected in the RNS Quantitative Template, incorporate the additional RPS-eligible renewable energy need resulting from expected participation in MCE’s voluntary 100 percent renewable energy service options.

During its bid evaluation and supplier selection processes, MCE considers a variety of risks and believes that such risks are sufficiently addressed within its MMoP calculation. Based on its operating history, previous experiences related to renewable energy planning/procurement and existing contract portfolio, MCE has no reason to doubt the sufficiency of the MMoP reflected in its RPS planning targets. MCE plans to procure to the VMoP since MCE’s internal RPS goals are 88 much higher than the state mandate. This noted, MCE has incorporated an internal RPS planning reserve, as reflected in the following table, to ensure MCE can meet its internal RPS targets in the event that its previously described contract management process identifies substantial concerns related to new-build project completion, delivery shortfalls or other issues.

This reserve is additive to MCE’s internally adopted RPS targets and intended to address renewable production and/or usage variability that may occur during discrete calendar years. It is intended to offset the potential impacts of noted risk adjustments and contingencies that may reduce actual renewable energy deliveries, relative to MCE’s expectations. In effect, MCE’s internal RPS planning reserve is a secondary VMoP, providing additional insurance against unforeseen circumstances that could impact MCE’s ability to satisfy its internally adopted renewable energy commitments. As demand- and supply-side data are monitored in each year, MCE may adjust planned short-term purchases and/or pursue surplus sales arrangements if actual renewable energy deliveries are tracking above MCE’s anticipated needs. By the end of each calendar year, MCE hopes to manage the level of its internal planning reserve so that actual renewable energy deliveries are closely aligned with MCE’s Base RPS Procurement Target, as reflected below.
89 Table 12: MCE RPS Procurement Target
SB 100 RPS
Procurement
Requirement
(% of Retail
Sales)
MCE’s
Internally
Adopted RPS
Procurement
Target (% of
Retail Sales)
MCE’s
Voluntary
Margin of Over-Procurement
(% of Retail
Sales)
MCE’s
Minimum
Margin of Over-Procurement
(% of Retail
Sales)
MCE’s
Aggregate
Margin of Over-Procurement
(% of Retail
Sales)
2025 46.7% 60.0% 13.3% 6.0% 19.3%
2026 49.3% 60.0% 10.7% 6.0% 16.7%
2027 52.0% 65.0% 13.0% 6.5% 19.5%
2028 54.7% 70.0% 15.3% 7.0% 22.3%
2029 57.3% 75.0% 17.7% 7.5% 25.2%
2030 60.0% 80.0% 20.0% 8.0% 28.0%
2031 60.0% 85.0% 25.0% 8.5% 33.5%
2032 60.0% 85.0% 25.0% 8.5% 33.5%
2033 60.0% 85.0% 25.0% 8.5% 33.5%
2034 60.0% 85.0% 25.0% 8.5% 33.5%
2035 60.0% 85.0% 25.0% 8.5% 33.5%
MCE will also model demand-side sensitivities that may impact MMoP and VMoP calculations. This will be particularly important during periods of expansion of MCE’s service area, when participation rates are expected to be most volatile. While MCE has no current expansion plans, MCE has completed numerous expansions during its 13-year operating history, and in each case, MCE has successfully scaled its renewable energy procurement to accommodate related increases in retail sales. In addition to load variability resulting from periodic expansions and ongoing minor fluctuations in customer participation, MCE will also monitor large load 90 growth (for example Data Center load growth), electric vehicle penetration rates, net energy metering participation rates and other considerations that may impact overall customer energy requirements and related procurement margin calculations.

X. Bid Solicitation Protocol
X.A. Bid Selection Protocols
(i) Description of Bid Solicitation Protocols.

In its various solicitations for long-term renewable energy supply, MCE imposes numerous bid requirements on interested respondents. These requirements address a variety of considerations and are intended to identify the best qualified suppliers of MCE’s long-term renewable energy needs. Such requirements include:

1. Overall quality of response, inclusive of completeness, timeliness, and conformity;

2. Price and relative value within MCE’s supply portfolio;

3. Project location and local benefits, including local hiring, prevailing wage considerations and community benefits packages;

4. Project development status, including but not limited to progress toward interconnection, deliverability, siting, zoning, permitting, and financing requirements;

5. Qualifications, experience, financial stability, and structure of the prospective project team (including its ownership);

6. Environmental impacts and related mitigation requirements, including impacts to air pollution within communities that have been disproportionately impacted by the existing generating fleet;

7. Potential impacts to grid reliability;
91 8. Potential economic benefits created within communities with high levels of poverty and unemployment;

9. Acceptance of MCE’s standard contract terms; and

10. Development milestone schedule, if applicable.

These considerations help shape the criteria against which prospective suppliers are evaluated. Based on the success of its ongoing planning and procurement efforts as well as any direction from its governing board, MCE may adapt these considerations in future renewable energy procurement efforts.

MCE considers minimum sizing requirements for certain long-term solicitations but does not solicit a specific quantity of projects, as this is based on the portfolio needs and the overall value of the project submissions. MCE considers a range of online dates based on the portfolio needs and the overall value of the project submission. MCE considers term lengths for long-term projects typically no shorter than ten years and no longer than twenty years.

Consistent with Public Utilities Code Section 399.13(a)(6)(C), MCE conducts energy product solicitations in a manner that addresses a broad range of considerations, including specific needs for eligible renewable energy resources (reflecting locational preferences, when applicable, for such resources), generating capacity, and required online dates to assist in determining what resources fit best within its desired supply portfolio. Since MCE’s governing board is comprised of local elected officials, solicitation and procurement decisions are overseen by elected representatives of MCE’s member communities with such decisions intended to conform with locally established targets that exceed applicable RPS requirements and promote the development of locally-situated renewable generating facilities.
92 (ii) Consideration of Resources Located in Disadvantaged Communities.

MCE requests information from prospective suppliers regarding whether their projects are located in disadvantaged communities and about their efforts to promote workforce development in these areas. These criteria are considered as a part of a comprehensive qualitative evaluation in addition to any benefits that enhance the value of the project through eligibility for related tax incentives for projects located in disadvantaged communities. (iii) Alignment of Bid Selection Criteria with RPS Procurement Plan.

MCE conducts its bid selection in accordance with the goals and preferences outlined in this RPS Procurement Plan in order to meet its portfolio needs, including but not limited to meeting all of its compliance obligations, achieving the agency’s equity goals, and mitigating affordability concerns.
(iv) Description of Ongoing, Planned, and Proposed Solicitations MCE’s 2025 solicitations, including applicable contract templates and general information regarding MCE’s active solicitation processes, are available at the following website:
https://www.mcecleanenergy.org/solicitations/. Information regarding other MCE service offerings and programs, including its FIT, can be found elsewhere on the MCE website.37 X.B. Solicitation Protocols for Renewables Sales
MCE does not have immediate plans to issue a solicitation for sales of renewable energy projects.
37 For example, information on MCE’s FIT program can be found at https://mcecleanenergy.org/feed-in-tariff/.
93 X.C. LCBF Criteria
The Least-Cost Best Fit (“LCBF”) methodologies approved by the Commission pursuant to D.04-07-029, D.11-04-030, D.12-11-016, D.14-11-042, and D.16-12-044 are expressly only directly applicable to investor-owned utilities. However, consistent with Section 399.13(a)(9),38 MCE does consider best-fit attributes that support a balanced mix of resources to help support grid reliability.

Regarding MCE’s application of an LCBF methodology during selection of qualified responses, the term “costs” should appropriately include considerations beyond the basic price of renewable energy being considered for procurement. Specifically, costs should include considerations such as: (1) reputational damage resulting from failure to meet internally established renewable energy procurement targets; (2) compliance penalties resulting from failed project development efforts or delivery shortfalls; (3) administrative complexities related to dealing with inexperienced suppliers (such as prolonged contract negotiation processes and uncertainties related to project milestone timing and achievement); and (4) impacts to planning certainty resulting from higher-risk projects. MCE considers these factors, among others, as part of its cost evaluation process, which may lead to the selection of offers that are not necessarily the lowest-priced option.

The term “fit” has as much to do with organizational compatibility between buyers and sellers and alignment with key organizational objectives as it does with balancing customer usage and expected project deliveries, particularly when considering long-term contracting opportunities that will require constructive working relationships over a period of ten years or 38 Cal. Pub. Util. Code § 399.13(a)(9) (“In soliciting and procuring eligible renewable energy resources, each retail seller shall consider the best-fit attributes of resource types that ensure a balanced resource mix to maintain the reliability of the electrical grid.”). 94 more. In recent Open Season solicitations, MCE added a focus on matching supply to the hourly load shapes and evaluate projects based on the overall fit of the portfolio. As such, MCE’s LCBF methodology takes into consideration the various planning and procurement processes described in this RPS Procurement Plan, balancing a variety of pertinent considerations at the time that each renewable purchase opportunity is being considered.

An important example supporting this perspective is MCE’s FIT program, which is intended to incentivize, through above-market prices, the development of locally situated, small-scale renewable project developments. This program has achieved tremendous success, supporting numerous projects throughout MCE’s service territory while utilizing local labor. By design, FIT projects are not the least expensive generating resources, but they are entirely consistent with MCE’s charter objectives and a valuable component of MCE’s supply portfolio.

This holistic planning approach, which may not necessarily reflect a traditional LCBF methodology, has resulted in the compilation of a diverse resource mix for MCE, deep roots in its member communities, and attention to a broad spectrum of considerations, including environmental concerns, costs and sustainability.

Finally, the requirement of Section 399.13(a)(8) to give preference to renewable projects located in certain communities is expressly only applicable to “electrical corporations” and is not mandatory for CCAs.39 However, MCE fully recognizes the need to help mitigate the impacts of air pollution in regions of the state where communities have been disproportionately impacted by the existing generating fleet as well as the need to bring economic benefits to communities with 39 Cal. Pub. Util. Code § 399.13(a)(8)(1) (“In soliciting and procuring eligible renewable energy resources for California-based projects, each electrical corporation shall give preference to renewable energy projects that provide environmental and economic benefits to communities afflicted with poverty or high unemployment, or that suffer from high emission levels of toxic air contaminants, criteria air pollutants, and greenhouse gases.”). 95 high levels of poverty and unemployment. As noted previously, MCE submitted Advice Letters to participate in the CPUC’s DAC-GT program and held a solicitation in 2021 for qualifying resources where two projects were selected and contracts were executed as part of the “Green Tariff” program. Since D.24-05-065 has made additional capacity available for the DAC-GT program, MCE plans to hold another solicitation to fill the new open program capacity. MCE continues to explore opportunities to advance this important policy goal through its procurement.

XI. Safety Considerations
MCE holds safety as a top priority. Since MCE does not own, operate, or control generation facilities, MCE’s procurement of renewable resources does not present any unique safety risks.

MCE’s Power Purchase Agreement includes safety terms such as Prudent Operating Practice and Maintenance of Health and Safety provisions, which speak to safety precautions with respect to the operation, maintenance, repair, and replacement of a project.

XI.A. Wildfire Risks and Vegetation Management
At this point in time, MCE has yet to adopt any additional safety requirements for its portfolio that are specific to wildfire risks and vegetation management. MCE is aware of the mitigating impacts that biomass generators, which use forestry waste as feedstock, may have on wildfire risk, and has adopted principles on responsible biomass electricity development which state that MCE will prioritize resources that support sustainable forest management and wildlife 96 reduction strategies to minimize the fuels for uncontrolled wildfire.40 As mentioned in Section III, MCE has engaged with the CPUC on laying the policy foundation for CCA participation in the BioMAT program, which is inclusive of woody biomass facilities that use feedstock from fuel reduction facilities or sustainable forest management, including from such feedstocks from high hazard zones.41
XI.B. Decommissioning Facilities
MCE does not own any generating assets, and as such does not undertake decommissioning of assets. MCE has not yet developed any plans or requirements related to the disposition of associated generating facilities following completion of applicable delivery terms. In many cases, the project’s operational life is longer than MCE’s contract, so it is likely that the contract with MCE will expire before disposal of the generation assets is required.

In 2015, SB 489 authorized the California Department of Toxic Substances Control (“DTSC”) to add PV panels to the list of universal wastes. The DTSC has developed regulations for PV panels but has not adopted the regulations yet.42 Because a significant portion of MCE’s solar facilities are newly constructed, and its storage facilities are yet to be constructed, MCE is confident that by the time PV solar or battery facilities under contract with MCE reach the end of their useful life, there will be statewide, comprehensive regulations addressing the safe handling and disposal/recycling of those materials.
40 See https://www.mcecleanenergy.org/wp-content/uploads/2021/11/MCE-Technical-Committee-Packet-Thursday-November-4-2021.pdf at 106. 41 PG&E’s BioMAT Market Adjusting Tariff, Section 14.c, Sheet 22:
https://www.pge.com/assets/pge/docs/about/doing-business-with-pge/ELEC_SCHEDS_E-BioMAT.pdf 42 See https://dtsc.ca.gov/photovoltaic-modules-pv-modules-universal-waste-management-regulations/. 97 XI.C. Climate Change Adaptation
MCE’s commitment to increasing renewable energy at a more aggressive pace than California’s statewide mandates itself constitutes a climate change adaptation measure.

Additionally, MCE in 2019 adopted a pollinator-friendly habitat requirement for solar projects participating in both its FIT program as well as its PPAs.43 MCE is the first California CCA to adopt this requirement, demonstrating a critical function that MCE, as a CCA, can take to help build and maintain healthy ecosystems in the local areas where MCE’s solar projects are located.

MCE will continue to evaluate the potential impacts of climate change on its portfolio so that adjustments to its procurement strategy can be made as needed.

XI.D. Impacts During Public Safety Power Shut-off Events Public Safety Power Shut-off (“PSPS”) events have both supply and demand side impacts.

MCE assesses customer usage as a result of a PSPS event, to the extent possible with the data to which MCE has access, in real time and adjustments to supply are made accordingly.

Generation resources that are located in the footprint of a PSPS event are necessarily taken offline, though MCE continues to explore ways to safely keep these resources online and serving customers. MCE is an active participant in the Commission’s Enhanced Power Line Safety Settings (“EPSS”) proceeding44 to help ensure that state policy as well as IOU and CCA operating protocols are aligned and result in minimal PSPS impacts in the future. 43 See https://mcecleanenergy.org/pollinator-friendly-ground-cover-now-required-for-new-solar-projects/. 44 R.24-05-023 and R.19-09-009, respectively.
98 XI.E. Forest Biomass Procurement
In recent renewable Open Season requests for offers, MCE has not received offers from forest biomass generators. MCE’s FIT program is available on a first-come, first-served basis, and is also technology-agnostic, however, MCE has not received any forest biomass applications.

As MCE works toward a low emissions portfolio, MCE will be seeking non-emitting renewable technologies to contribute to its existing bioenergy resources already under contract. As mentioned in Section XI.A, MCE has been engaged in the implementation of BioMAT, which does have a dedicated category for the procurement of woody biomass facilities. Although MCE participated in laying the policy foundation for CCA participation in the BioMAT program in R.22-10-010, at the time of this filing MCE is not actively participating in the BioMAT program.

XII. Consideration of Price Adjustment Mechanisms
At the time of this filing, MCE has not currently adopted any specific price adjustment mechanisms. However, in light of the current political landscape and ongoing affordability concerns for LSEs and ratepayers throughout California, MCE may consider incorporating price adjustment mechanisms to protect ratepayers from market uncertainty.

XIII. Cost Quantification
MCE has provided the Cost Quantification Table as Appendix E. Pursuant to the direction in the ACR, MCE has completed those cells in the Cost Quantification table that correspond to Table 3, Rows 1-5 in the ACR.

XIV. Impact of Transmission and Interconnection Delays
SB 1174 (stats. 2022, ch. 229) requires electrical corporations that own transmission lines to report to the Commission on the development of transmission and interconnection facilities necessary to provide transmission deliverability for renewable energy and/or energy storage 99 facilities that have executed interconnection agreements. MCE is not subject to the requirements of SB 1174 and does not own any transmission lines. Accordingly, MCE has not included a Transmission/Interconnection Delay Data Report as an attachment to this RPS Procurement Plan.

Dated: June 30, 2025 Respectfully submitted,
/s/Sai Powar
Sai Powar
Policy Analyst
Marin Clean Energy
1125 Tamalpais Avenue
San Rafael, CA 94901
(415) 464-6044
[email protected]
Appendix A
Redlined Version of Draft 2025 RPS Plan
(Public Version)

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue
Implementation and Administration, and Consider
Further Development, of California Renewables
Portfolio Standard Program.

Rulemaking 24-01-017
DRAFT 20252024 RENEWABLES PORTFOLIO STANDARD PROCUREMENT PLAN OF

MARIN CLEAN ENERGY

PUBLIC VERSION
Sai PowarAmulya Yerrapotu
Policy Analyst
Marin Clean Energy
1125 Tamalpais Avenue
San Rafael, CA 94901
(415) 464-60446670
[email protected]
Dated: June 30, 2025July 23, 2024
1 BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue
Implementation and Administration, and Consider
Further Development, of California Renewables
Portfolio Standard Program.

Rulemaking 24-01-017
DRAFT 20252024 RENEWABLES PORTFOLIO STANDARD PROCUREMENT PLAN OF

MARIN CLEAN ENERGY

PUBLIC VERSION
In accordance with the California Public Utilities Commission’s (“Commission” or “CPUC”) AprilMay 17, 20252024, Assigned Commissioner and Assigned Administrative Law Judges’ Ruling Identifying Issues and Schedule of Review for 20252024 Renewables Portfolio Standard Procurement Plans (“ACR”), Marin Clean Energy (“MCE” or “Agency”), hereby submits this Draft 20252024 Renewables Portfolio Standard Procurement Plan (“RPS Procurement Plan”). As directed by the ACR, this RPS Procurement Plan includes responses for the issues expressed in ACR sections 6.1-6.1517.

In reviewing this RPS Procurement Plan, MCE encourages the Commission to consider the differences between California’s investor-owned utilities (“IOUs”) and other retail sellers, including CCAs. Differing levels of detail, procedure, complexity, and coordination within the planning documents submitted by these organizations are appropriate.

I. Summary of Major Changes to RPS Plan
This Section describes the most significant changes between MCE’s Draft 20242023 RPS Procurement Plan (which was deemed as final by Decision 2423-12-035008) and its Draft 20252024 RPS Procurement Plan. A redline of this Draft 20252024 RPS Plan against MCE’s Draft 20242023 RPS Plan is included as Appendix A. The table below provides a list of key differences between MCE’s 2023 and 2024 and 2025 RPS Procurement Plans.

Table 1: Key Changes to MCE's RPS Procurement Plan
Plan Reference Plan Section Summary/Justification of
Change
20252024 RPS Procurement
Plan: Section IV
Assessment of RPS Portfolio
Supplies and Demand Updated to provide latest
information on MCE’s
progress towards meeting the
requirements of Mid-Term
Reliability Decision, D.21-06-
035, D.23-02-040, and
potential RPS planning
implications.
20252024 RPS Procurement
Plan: Section I.V.B.2 Curtailment Frequency,
Forecasting, CostsProject
Development Status Updates
Updated information
regarding historical
curtailments in Calendar Year
2024 and Calendar Year 2025
to date.Updated the project
development status template,
Appendix D, to reflect the
recent progress of renewable
3 generating projects that have
yet to achieve commercial
operation. Updated narrative
to describe projects, including
status of delays and contract
online dates.
20252024 RPS Procurement
Plan: Section VIV.A.1 Project Development Status
UpdatesPortfolio Optimization
Updated the project
development status template,
Appendix D, to reflect the
recent progress of renewable
generating projects that have
yet to achieve commercial
operation. Updated narrative
to describe projects, including
status of delays and contract
online dates.Updated to
reflect how MCE is
optimizing existing resources
and future procurement to
meet new CPUC reliability
goals.
20252024 RPS Procurement
Plan: Section IV.CVII
Portfolio OptimizationRisk
Assessment
Updated to reflectinclude
further detail on how MCE is
optimizing existing
resourcesevaluates risk,
especially in light of Mid-Term Reliability Decision,
D.21-06-035 and future
procurement to meet new
CPUC reliability goalsD.23-
02-040.
20252024 RPS Procurement
Plan: Section VIIVIII
Risk AssessmentRenewable
Net Short Calculation
Updated to include further
detail on how MCE evaluates
risk, especially in light of
Mid-Term Reliability
Decisions, D.21-06-035 and
D.23-02-040.Updated the
Renewable Net Short
template, Appendix C, to
reflect actual data through
4 2023 and updated projections
through 2034.
20252024 RPS Procurement
Plan: Section VIIIXIII
Renewable Net Short
CalculationCurtailment
Frequency, Forecasting, Costs
Updated the Renewable Net
Short template, Appendix C,
to reflect actual data through
2024 and updated projections
through 2035. Updated
information regarding
historical curtailments in
Calendar Year 2023 and
Calendar Year 2024 to date.
20252024 RPS Procurement
Plan: Section XIV
Cost Quantification Updated Cost Quantification
template, Appendix E, to
reflect updated cost
projections associated with
actual and planned RPS
procurement through 2034.

II. Executive Summary Key Issues
In this Draft 20252024 RPS Procurement Plan, MCE provides information and updates regarding its progress in meeting applicable renewable energy planning and procurement targets, as well as additional detail in response to the expanded requirements set forth in the ACR.

MCE, California’s first CCA, is a not-for-profit public agency that began service in 2010 with a mission to confront theaddress climate crisischange by eliminating fossil freereducing energy-related greenhouse gas emissions, producing with renewable energy, and energy efficiency at cost-competitive rates while offering economic and workforce benefits and creating more equitable community benefits.communities. In 20242023, MCE served approximately 585,000 customer accounts in 37 communities across Contra Costa, Marin, Napa, and Solano counties, with annual retail sales of approximately 5,500 gigawatt hours. Beginning in 2025, MCE expanded its service area towill serve 38 communities with the inclusion of the City of Hercules.. MCE offers 5 its customers a 60% renewable default service (“Light Green”), as well as two 100% renewable energy service options (“Deep Green” and “Local Sol”).

MCE is governed by a board of Directors (“Board”) comprised of 3634 locally elected officials. The Board sets policy for the Agency and oversees its operations. Depending upon the issue, representatives from MCE’s governing board and committees generally convene two to three times per month with advance public notice provided in compliance with the Brown Act.

MCE updates its biennial Compliance Integrated Resource Plan (“IRP”) mandated by SB 350 (2015). The Compliance IRP submitted to the Commission biennially has been primarily oriented towards supporting California’s achievement of its 2030 Greenhouse Gas (“GHG”) reduction targets. MCE’s internal commitment to clean energy has resulted in a default supply portfolio that reached 60% renewable in 2017, thirteen years ahead of the statewide procurement mandate. MCE is also attentive to applicable long-term renewable energy contracting requirements and has secured 65105% of its total projected 20252024 RPS requirements (relative to California’s interim annual RPS procurement mandate) via numerous long-term contracts, exceeding pertinent long-term contracting requirement established by SB 350 (2015). MCE observes that it has also procured over 100% of its voluntary, internally adopted renewable energy need, which, in aggregate, approximates 76% of projected retail load. MCE is also fully compliant with all CPUCCommission Resource Adequacy (“RA”) requirements, to support the reliability needs of the state.

MCE maintains its clean, balanced portfolio by closely monitoring ongoing market conditions, including but not limited to curtailment, customer demand, and policy changes. MCE also monitors unanticipated market events, such as inflationary and supply chain pressures and 6 their impacts on both the supply and demand sides of the market.1 In optimizing its portfolio, MCE
prioritizes the maintenance of a balanced, diverse, and reliable portfolio; adhering tokeeping its commitment to clean energy; and suppressing customer costs to the greatest practical extent.

MCE’s commitment to clean energy has led to the exploration ofAgency to explore opportunities to mitigate the impacts of air pollution in regions of the state where communities have been disproportionately affected by the existing generating fleet, as well as the need to bring economic benefits to communities with high levels of poverty and unemployment. To address this concern, MCE continues to evaluate the procurement of “clean resource adequacy” (“Clean RA”) and the feasibility (both technological and economic) of transitioning to increased use of carbon-free capacity sources to meet statewide reserve capacity mandates.

MCE’s RPS Procurement Plan details its current solicitations and its bid review and selection processes. The Plan also describes how MCE applies the Least-Cost Best Fit concept to its portfolio, to support its priorities as an agency created to providefor the purpose of providing clean energy, amongstamong other customer- and community-focused service offerings and programsthings.

III. Compliance with Recent Legislation and Impact of Regulatory Changes 1 Post COVID-19 impacts are discussed more fully in Sections IV and VI, below. 7 This RPS Procurement Plan addresses the requirements of all relevant legislation and the Commission’s regulatory framework and . This Section describes the relevant statutory and regulatory requirements and how this RPS Procurement Plan demonstrates that MCE meets these requirements.

SB 350 was signed by the Governor on October 7, 2015. SB 350 set a new RPS procurement target of 50% by December 31, 2030. On December 20, 2016, the Commission issued Decision (“D.”) .16-12-040, which partially implemented the increased targets of SB 350 by establishing new compliance periods and procurement quantity requirements. On July 5, 2017, the Commission issued D.17-06-026, which implemented some of the key remaining elements of SB 350, including adopting new minimum procurement requirements for long-term contracts and owned resources, as well as revising the excess procurement rules. As discussed in greater detail in Section IV.AB.1, MCE projects that 96105% of its total projected 20252024 RPS procurement target will be met with long-term contracts; MCE further expects that nearly 87100% of mandated RPS purchases related to Compliance Period 4 will be fulfilled via deliveries from long-term renewable energy contracts.

SB 100 was signed by the Governor on September 10, 2018, and became effective on January 1, 2019. SB 100 increased the RPS procurement requirements to 44% by December 31, 2024, 52% by December 31, 2027, and 60% by December 31, 2030. On June 6, 2018, the Commission issued D.18-05-026, which implemented changes made by SB 350 to the RPS waiver process and reaffirmed the existing RPS penalty scheme. In July of 2018, the Commission instituted Rulemaking (“R.”) 18-07-003 to continue the implementation of the RPS program. On June 28, 2019, the Commission issued D.19-06-023, which continues to use a straight-line method to calculate compliance period procurement quantity requirements. The current RPS procurement 8 targets are incorporated in MCE’s Renewable Net Short (“RNS") Calculation Table as further described in Section VIII below and attached hereto as Appendix C. On a projected basis, MCE’s current RPS procurement is sufficient to exceed applicable, internally adopted renewable energy procurement targets through 20252024, including the minimum margin of over-procurement based on MCE’s risk assessment, as further described in Sections VII and IX.

In accordance with SB 255 (Bradford, 2019), D.22-04-035 revises the Commission’s Supplier Diversity Program set forth in General Order (“GO”) 156 to incorporate CCAs, Energy Service Providers (“ESPs”), and smaller utilities with certain revenue thresholds. MCE is committed to supporting sustained and fairly compensated local job opportunities through participation in the clean energy industry. To the extent allowed by state law, MCE seeks to create market incentives and partnerships to encourage diversity and a sustainable workforce through its support for:
● Fair compensation in direct hiring, renewable development projects, customer programs, internships, and procurement services;
● Development of locally generated renewable energy within the MCE service area; 9 ● Direct use of union members from multiple trades;
● Quality training, apprenticeship, and pre-apprenticeship programs; ● Direct use of businesses local to the MCE service area; ● Development of California-based job opportunities;
● Business and workforce initiatives located in low-income and disadvantaged communities;
● Direct use of Disabled Veteran-owned Business Enterprises and LGBT-owned Business Enterprises;
● Direct use of green and sustainable businesses; and
● Use of direct hiring practices that promote diversity in the workplace.

MCE has submitted annual supplier diversity reports to the CPUC since 2020, the first year SB 255 was in effect.2
These reports follow the same timeline and reporting structure thatas applies to the other entities that report to the CPUC annually under GO 156, adjusted to account for MCE’s status as a public agency subject to Proposition 209.3MCE and other CCAs have been working with the CPUC’s Supplier Diversity staff since the passage of SB 255 to ensure reporting requirements for CCAs are appropriate and conform to SB 255, and will continue to do so on an 2 See https://mcecleanenergy.org/wp-content/uploads/2024/06/MCE_Supplier-Diversity-Report_FINAL.pdf for MCE’s 2024 Supplier Diversity report 3 Proposition 209 was approved by voters in 1996 and amended the California Constitution to prohibit the state, including local government agencies, from discriminating or granting preferential treatment on the basis of race, sex, color, ethnicity, or national origin in the operation of public employment, public education, and public contracting. 10 ongoing basis, as set forth in D.22-04-035.

Assembly Bill (“AB”) 843 (Aguiar-Curry, 2021) authorizes CCAs to submit eligible bioenergy projects for cost recovery pursuant to the Bioenergy Market Adjusting Tariff (“(BioMAT”)) program. The BioMAT program is a feed-in tariff program for small bioenergy renewable generators less than 5 megawatts (“MW”) in size, offering 250 MW total to eligible projects through a fixed price standard contract to export electricity to California’s IOUs and now, CCAs. Electricity generated through the BioMAT program counts towards RPS targets. MCE engagedMCE is engaging in R.22-10-010 and is working with the California Community Choice Association (“CalCCA”), the CPUC, and the IOUs to establish program implementation details to facilitate CCA participation in the program; however, MCE does not participate in this program currently. .SB 1109 (Caballero, 2022) and AB 2750 (Gallagher, 2023) requirerequires entities, including CCAs, with a contract to procure electricity generated from biomass that expires or expired on or before December 31, 2028, to amend or establish a new contract that includes an expiration date five5 years later than the expiration date in the contract that was operative in 2022.

MCE does not have any contracts that fit this requirement.

SB 1020 (Laird, 2022) sets interim targets for renewable and zero-carbon energy in California, requiring 90% of all retail sales of electricity be zero-carbon by December 31, 2035, and 95% of all retail sales of electricity be zero-carbon by December 31, 2040. MCE’s most recent Operational Integrated Resource Plan (“(OIRP”)) adopted interim targets that are more stringent than what iswhat’s required for SB 1020,4therefore, MCE expects to meet these goals. 4MCE’s Light Green service option is expected to be 95% GHG-free by 2023 and is expected to reach 85% renewable energy by 2029.
https://www.mcecleanenergy.org/wp-content/uploads/2021/11/MCE-Operational-Integrated-Resource-Plan_2022.pdf.pdf. 11 Additionally, MCE is working with state partners to understand the requirements of SB 1020 for other agencies and exploring how to support those other agencies in meeting SB 1020 goals. In the interim, MCE notes that state agency accounts may enroll in one of MCE’s 100% renewable energy service optionoptions, Deep Green or Local Sol, to immediately receive zero-carbon retail energy service.

AB 1373 (Garcia, 2023) alsoAB 1373 (Garcia, 2023) requires the CPUC to include cost-effective resource diversity in its integrated resource planning processes. The bill permits CCAs to satisfy their portion of the CPUC’s resource diversity requirements so long as the CCA’s proposal promotes the efficient achievement of state energy policy objectives and does not result in incremental costs to bundled customers. The CPUC is currently implementing AB 1373 and is 12 in the process of developing a new IRP framework, the Reliable and Clean Power Procurement Program (“RCPPP”). In March 2025, the CPUC put forth its proposal on RCPPP that included reliability procurement and GHG reduction target frameworks for stakeholder consideration MCE is engaging in R.20-05-003 and working with CalCCA to facilitate effective design of the new program and establish reasonable implementation details.. MCE will address requirements set forth in the RCPPP after the program’s adoption and tentative implementation in 2027. this requirement in its next IRP in 2025.

IV. Assessment of RPS Portfolio Supplies and Demand
IV.A. Portfolio Supply and Demand
(i) Assessment of Portfolio Supply and Demand through 2035 MCE continues to project that it will meet or exceed applicable RPS procurement obligations over the long-term planning horizon (through 20352034, which reflects the final year of the planning period addressed in this document). The exact characteristics of MCE’s renewable supply portfolio are expected to vary over the planning horizontime based on a variety of considerations, including market developments and RPS product availability, policy changes, technological improvements, Agency preferences, and/or myriad other factors.

Of note, Due to apparent RPS supply constraints, which affected Portfolio Content 13 Category 1 (“PCC1”)5appear to be affecting product availability and pricing in 2024 and 2025through Compliance Period 5, MCE observes that Product Content Category 1 (PCC1) 6 prices have increased more than 400% during the 18-month period between November 2022 and June 2024. While the full scope of circumstances contributing to this pricing runup remains unclear, many retail sellers, including MCE, were subjected to substantial budgetary impacts in meeting adopted portfolio objectives. The unexpected rise in RPS prices and the associated changes in regional short-term renewable energy markets impact how MCE can balance customer affordability with achieving environmental objectives that generally exceed statewide mandates.

Between June 2024 and June 2025, PCC1 prices declined for product vintages to be delivered in 2026 and beyond, and while such prices have yet to return to "historical norms,” there has been budgetary relief for load serving entities (“LSE”) needing to procure incremental RPS supply thus far in Compliance Period 5. The previously described PCC1 pricing volatility is reflectedover the past 18 to 24 months as depicted in the following bar chart, which identifies average historical prices observed by MCE for index-plus PCC1 transactions over the past approximate 18-month term. MCE observes that “historically normal” PCC1 levels during the several years leading up to late 2022 were generally at/below $20/megawatt hours (“MWh”) for index-plus transactions. .
5 A resource which is either located within California, or directly delivers to California without substituting energy from another source.
6 A resource which is either located within California, or directly delivers to California without substituting energy from another source.
14 Figure 1: MCE’s PCC1 Renewable Price 2024-2026
This recent price volatility highlighted a relatively new, but significant, risk facing buyers of short-term renewable energy products which, for several years, had experienced relatively low levels of pricing variability. State procurement directives, including the mid-term reliability and supplemental mid-term reliability programs, have had the effect of multiple buyers entering the market at the same time due to the universally applicable schedule of compliance deadlines assigned through such processes. Additionally, recent tariff discussions have introduced the risk of substantive cost increases for certain projects. These factors have exerted upward pressure and considerable uncertainty on certain technology/project types, which may play meaningful roles in California meeting its eventual RPS goals – particularly in a way that balances affordability for ratepayers. MCE continues to assess the best approach for dealing with these risks which may be subject to considerable iteration. For example, taking on additional long-term contracts, which can often promote increased price stability within an RPS contract portfolio (even though overall costs associated with such contracts can be higher than prices identified in short-term markets) could mitigate exposure to the occasional volatility experienced in short-term RPS markets. 15 However, disproportionately high levels of long-term contracting could reduce planning flexibility, including a retail seller’s ability to take advantage of emerging technologies, adapt to policy changes, and react to periodic market fluctuations.

In the near termAccordingly, MCE expects budgetary and rate-related impacts associated with addressing prior (2024 and 2025) and projected (2026 and 2027) RPS that the cost to address outstanding PCC1 open positions may be especially large, but MCE remains committed to fulfilling its internally adopted RPS targets as planned. Thankfully, due to prudent planning, MCE is well resourced for the early stages of Compliance Period 52024, so its short-term RPS procurement efforts will be predominantly focused on outstanding needs in 2026 and 2027, years in which prices have recently subsided. Over the long-term planning horizon, MCE believesCompliance Period 5. During periods of constrained RPS supply, including the situation that its disciplined and diversified approach to RPS procurement California is dealing with now, MCE will lead to average portfolio costs that are manageable and considerate of customer rate sensitivities as well as statewide planning needspay particularly close attention to its forecasted energy requirements to avoid unnecessary/excessive procurement of overly costly supply. 16 As previously noted, MCE’s internally adopted renewable energy procurement targets have been set in excess of state-imposed mandates, creating a natural compliance buffer. For example, approximately 7468% of MCE’s aggregate supply portfolio was comprised of RPS-eligible renewable energy in 20242023, an amount exceeding the state’s interim annual procurement mandate by nearly 6866%. Similar to previous years, this significant level of over-procurement would have accommodated massive fluctuations in annual retail sales and/or anticipated renewable energy deliveries before triggering potential compliance risks for MCE.

Given the significance of MCE’s internally established 60% renewable target (which persists through 2025 before increasing thereafter), past success exceeding applicable compliance mandates, existing supply commitments and ongoing planning/procurement efforts focused on RPS-eligible energy, MCE does not foresee any issues fulfilling future renewable supply commitments.

Additionally, MCE is aware that supply chain impacts continue to exist, and for renewable energy projects that have yet to achieve commercial operation, MCE will closely monitor progress in case such issues impact expected online dates. Federal policy changes regarding Tax Credits and imposition of significantly increased tariffs that could be applied to certain renewable 17 and battery storage infrastructure is another important concern being monitored by MCE, as such risk is often being addressed by “price reopener” provisions inserted in various renewable energy contracts. These provisions not only create the potential for budgetary uncertainty but also the reality that extreme price increases may compromise the prospect of project completion (via contract termination), leaving the affected retail seller to search for project alternatives that may be necessary to backfill vacated supply. Regarding demand side impacts, these are often more challenging to isolate, as normal variations in usage caused by weather may obscure otherwise atypical variations in consumption. With current monetary policy focused on controlling inflation, MCE will be attentive to potential changes in customer usage that may result from ongoing policy adaptations, particularly those intended to control persistent inflationary pressures. Based on available data and related analyses conducted to date, impacts to MCE’s overall load and sales appear to be relatively modest.
(ii) Assessment of Need for RPS Resources with Specific Deliverability Characteristics
MCE regularly analyzes and assesses its renewable portfolio mix to identify supply, fit, and compliance needs. While compliance with the RPS program has not been an issue of concern, as California increases its renewable and carbon free targets, there is a need for MCE to continue diversifying its resource mix. Resources with diverse deliverability characteristics help in mitigating risk exposure to market forces while providing grid reliability. Peaking dispatchable resources, such as storage paired with solar or wind, are critical in meeting high demand periods in the future. However, this requires having baseload resources like geothermal to allow for the flexibility to dispatch marginal resources as load shifts. Reliance on intermittent resources like solar and wind alone exposes one to congestion and potential curtailment risks.

This risk continues to grow with the accelerated adoption of solar and wind on the grid. MCE is 18 aware of these factors and continues to pursue a diverse set of renewable resources to not only meet its RPS obligations but also maintain operational flexibility while contributing to overall system reliability.
(iii) Experience Managing Exposure to Negative Market Prices MCE closely monitors twelve separate locations that are indicative of renewable energy resources that are exposed to market prices and potential curtailment. Resources at those locations are bid into the CAISO markets and are curtailed when prices fall below individual resource’s threshold prices. Weighted average prices for the generation at those locations are compared to weighted average prices at Pacific Gas and Electric’s (“PG&E”) Default Load Aggregation Point (“DLAP”) to assess the impact of congestion on the resource’s performance. In addition, the MWh of curtailment are logged.

If curtailment is caused by congestion, the impact can be somewhat mitigated by obtaining CAISO Congestion Revenue Rights (“CRRs”), which MCE has done. However, CRRs are not a 19 perfect hedge against congestion and cannot be relied upon to mitigate congestion and subsequent economic curtailment entirely. MCE will continue to monitor and plan for managing exposure to negative market prices.
(iv) Assessment of how the Renewable Net Short Quantitative Analysis Supports the Assessment of Portfolio Supply and Demand
As reflected in MCE’s RNS appendix, MCE aims to procure sufficient quantities of renewable energy that: 1) meaningfully exceed statewide procurement mandates via internally adopted RPS procurement targets that range from 10.7% to 25.0% above the state’s interim annual RPS procurement targets throughout the planning period (2025-2035); and 2) reflect a 10% planning reserve (in excess of projected, internally adopted RPS targets that meaningfully exceed statewide mandates) to ensure that production from intermittent resources, curtailments, potential project delays or failures, and/or other unexpected circumstances that could otherwise reduce anticipated renewable energy deliveries, do not adversely impact MCE’s ability to fulfill publicly communicated renewable energy portfolio goals. These planning decisions serve as formidable protections against renewable energy delivery shortfalls. (v) Assessment of how Procurement or Allocations are Consistent with the Evaluation of Supply and Demand
MCE has assembled a broadly diverse renewable energy contract portfolio, meaning that MCE’s portfolio is attentive to technological diversity, temporal diversity, geographic diversity, and supplier diversity. These planning considerations, coupled with MCE’s voluntary procurement targets that meaningfully exceed statewide mandates, minimize sources of planning vulnerability and prevent the risk of RPS compliance shortfalls. In terms of serving customer energy requirements, MCE’s diverse portfolio, which includes baseload, peak, off-peak, seasonal, and dispatchable delivery profiles, is generally complementary to the manner in which MCE’s 20 customers use electric power. Dispatchable renewable resources, specifically co-located solar and battery infrastructure, allow for the shaping of certain renewable deliveries to promote improved alignment between supply and demand. Over time, MCE will continue to evaluate customer energy requirements and usage patterns relative to how its renewable resource portfolio delivers power and will pursue incremental procurement opportunities to better align supply and demand at least cost.

IV.A.1. Long-Term Procurement
(i) Assessment of How Current and Planned Procurement Meets 65 Percent Long-Term Contracting Procurement Requirement Through 2035.

MCE has been committed to supporting new, California-based renewable resource development since its inception, and has supported numerous generating assets via execution of long-term contracts. MCE has already executed long-term renewable contracts that are expected to yield approximately 96% of its total RPS/statutory renewable energy requirements (or 147% of MCE’s expected RPS-related long-term renewable energy requirements) in 2025. Further, most of the renewable energy supply solicited under MCE’s Open Season is intended for projects with proposed delivery terms between ten and twenty years, which bolsters MCE’s proportionate use of long-term renewable energy over time.
(ii) Quantitative Assessment of MCE’s Long Term RPS Positions The table below relates projected deliveries under MCE’s existing long-term RPS supply contracts to interim annual RPS procurement targets and related long-term contracting requirements.
21 Table 2: Projected RPS Deliveries
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
Proportionate
Long-Term
RPS Purchases
Relative to
Interim
Annual
Statutory
Procurement
Mandate 96% 95% 105% 118% 114% 108% 105% 102% 90% 85% 83% Proportionate
Long-Term
RPS Purchases
Relative to
Interim
Annual
Statutory
Long-Term
Contracting
Requirement 147% 146% 162% 182% 176% 166% 161% 157% 139% 131% 127% MCE’s substantial, ongoing commitment to long-term RPS contracting has created significant projected long-term RPS surpluses. As a result of such surpluses, there is an exceptionally low risk of MCE falling short of this aspect of the RPS compliance program.

MCE has included two additional bars in each grouping:
1) An unadjusted projection of MCE’s expected annual long-term contract deliveries, relative to the 65 percent mandate. This bar represents the proportionate relationship between MCE’s long-term contract deliveries and the statewide procurement mandate. For example, MCE projects that it will surpass the state’s long-term contracting requirement 22 by 47 percent in 2025 and is not expecting to fall below 100 percent of its long-term contracting requirement during the current planning period; and 2) An adjusted projection of MCE’s expected annual long-term contract deliveries relative to the 65 percent procurement mandate. This bar represents the proportionate relationship between MCE’s long-term contract deliveries (including an annual reduction in such deliveries equivalent to MCE’s established Minimum Margin of Over Procurement (“MMoP”), which reflects the potential impacts of delivery shortfalls related to resources intermittency, delays in commercial operation, resource curtailment, supply chain issues, and/or other operational issues) and the statewide mandate. MCE believes that this scenario represents a relatively extreme stress case. Nonetheless, MCE would expect to meet or exceed California’s long-term contracting mandate throughout the planning period.

Figure 2: MCE’s Projected Long-Term RPS Contracting Progress: 2025-2035 23 Note that the data underlying this bar chart has been compiled annually, which means that the percentages do not reflect the additional compliance flexibility related to California’s multi-year compliance periods. For example, if MCE exceeds the long-term procurement mandate by 47% in 2025, it could absorb meaningful delivery shortfalls in the other years encompassing Compliance Period 5 before any compliance deficits arise. Unadjusted projections of MCE’s long-term contracting progress suggest that MCE is expected to exceed applicable mandates through the current planning period. Likewise, adjusted projections also suggest that MCE will similarly exceed applicable mandates, even under a relatively extreme stress case such as the one reflected in the previous bar chart. MCE expects to engage in additional long-term contract efforts, which will further increase its long-term RPS positions as well as the compliance buffer already in place.
(iii) Summary of Current and Planned Long-Term RPS Procurement MCE maintains a diverse set of long-term power purchase agreements to meet its long-term procurement needs. This includes multiple geothermal, solar, wind, small hydro and solar plus storage resources. These contracts are staggered in nature, spanning 10 to 30 years in length. In addition, MCE is engaged in negotiations to add more generating and storage resources to the existing fleet. MCE does not anticipate any issues meeting its long-term requirements. (iv) Timeline Meeting 65 Percent Long Term Procurement Requirement.

MCE did not receive an SB 155 letter and does not expect any issues in meeting its long-term RPS contracting obligations, as described elsewhere in this Plan. 24 IV.B. Portfolio Diversity and Reliability
(i) Description of How Portfolio Diversity is Considered.

For example, renewable energy procurement efforts that may initially focus on relatively low-cost solar resources will often necessitate subsequent investments in co-located energy storage infrastructure and/or higher-cost baseload renewable generating technologies, such as those using geothermal, biomass and landfill gas fuel sources. These baseload renewable technologies are often priced at three-to-four times the level of in-state photovoltaic (“PV”) solar generation but generally provide increased capacity value due to the more predictable, baseload generating profiles of such resources, and related reliability enhancements. 25 Despite the adverse budgetary impacts, MCE continues to pursue resource acquisitions that will promote increased alignment between supply and demand as well as the increased use of locally situated renewable generating resources. Currently, low-cost, long-term solutions are incredibly challenging to identify, as ongoing increases in California’s RPS procurement mandates and technological limitations often create the need for near-term investments to balance the achievement of compliance mandates with generalized grid reliability.

In 2020, MCE also implemented an “equivalent carbon-free” portfolio metric, which considers the total emissions associated with each supply source relative to a target annual emission factor for its entire supply portfolio. For example, MCE’s 95% carbon-free equivalent goal in 2024 contributed to the achievement of an overall portfolio emission factor less than 1% of the California Air Resources Board’s (“CARB”) assigned emission factor for energy imports and system power, which is currently set at 0.428 metric tons of carbon dioxide equivalent per megawatt hour (“MT CO2e”). Expressed differently, the 95% carbon-free equivalent goal limited, on a voluntary basis, MCE’s emissions to an overall portfolio emission factor of 0.021 MT CO2e/MWh. As reflected in its current 2024 Power Source Disclosure (“PSD”) report for Light Green service,7MCE’s actual 2024 emission factor of 0.001 MT CO2e/MWh was below the organization’s 95% carbon-free equivalent emission target (reflecting a virtual 100% carbon-free equivalency for the Light Green portfolio. The emission factors for Deep Green, Local Sol and Green Access service, as reflected in MCE’s 2024 PSD report, were also zero.

As certain renewable generating technologies are known to have relatively low levels of emissions, such as certain geothermal generating technologies, MCE’s equivalent carbon-free metric captures such impacts, along with any other use of carbon-emitting supply, including 7The 2024 Power Source disclosure Report was submitted by June 1, 2025. 27 system power and CARB-certified Asset Controlling Supply, to derive its proportionate use of carbon-free generation. To the extent that MCE’s energy needs are not fulfilled using renewable or other GHG-free generating resources, it should be assumed that such supply will be sourced from conventional energy sources, such as natural gas generating technologies or system power purchases. MCE also plans to maintain its carbon-free equivalent metric at 95% of total supply in 2025 and beyond, meaning it will be further constrained in utilizing any carbon-emitting sources, including certain renewable generating technologies. As such, MCE will continue to creatively address the exercise of resource planning and portfolio composition to meet or exceed the aforementioned carbon-free equivalency metric.

A key component of this process relates to the analysis and consideration of MCE’s forward load obligations and existing supply commitments with the objectives of closely balancing supply and demand, cost/rate stability, and overall budgetary impacts, while leaving some flexibility to take advantage of market opportunities and/or technological improvements that may arise over time. MCE’s long-term load forecast is a projection of the energy (reflected in MWh) that its customers will consume annually. MCE’s long-term load forecast is driven primarily by the number and types of customers that MCE expects to serve, in conjunction with weather projections. Hourly class-specific load profiles are then used to break down the monthly energy forecast into more granular time-of-use and peak demand values. MCE’s long-term load forecast 28 also incorporates the load-modifying effects of electric vehicles, behind-the-meter solar and/or storage (via net energy metering), and energy efficiency.

MCE prefers zero emission generating technologies, but within this preference MCE is largely technology-agnostic, subject to the previously discussed carbon-free equivalency metric.8 MCE’s supply preferences are intended to exhibit diversity across a broad range of renewable technologies that will deliver energy in a profile that is generally consistent with MCE’s anticipated load shape. MCE is aware that significant use of intermittent renewable generating technologies has the potential to create misalignments between customer energy consumption and related power production; however, MCE regularly evaluates customer usage in light of expected renewable deliveries to reduce such risks and inform future procurement decisions. Furthermore, MCE continues to consider procurement opportunities with renewable generating facilities that will utilize storage technology, which can materially re-shape the typical delivery profile 8 As mentioned above, MCE has a policy of not pursuing resource-specific nuclear power purchases.
29 associated with intermittent renewable generating assets, providing the opportunity for MCE to more accurately balance supply and changing customer demand, particularly due to the potential expansion of transportation electrification. MCE is also considering stand-alone energy storage opportunities to “recontour” purchased energy volumes in a manner that better matches changing customer usage patterns. MCE has determined that such projects are comparatively costly due to infrastructure costs and, in the case of battery storage projects, losses stemming from the common charge/discharge cycle of such projects.

Additionally, MCE offers several programs to manage its load shapes and better align MCE’s supply resources with hourly demand. For example, MCE currently offers a managed EV charging app, MCE Sync, which helps customers automate EV charging and shift consumption away from peak periods.9Additional programs to help better align supply and demand include but are not limited to: MCE’s Peak FLEXmarket;10 Time of Use (“TOU”) rates;11 and MCE’s revised Feed-In-Tariff (“FIT”) Plus program,12 that requires the addition of storage equal to 180% of the generator’s nameplate capacity and enables generation to be shifted outside of normal solar production hours to better align MCE resources to match the hourly load.13 Recent market data continues to indicate that midday peak resources are likely to comprise a larger proportion of California’s renewable supply portfolio due to the rapid decline in wholesale prices for solar PV generation and the abundance of such projects in operation and under development. Additions to MCE’s portfolio during the Planning Period will likely be more heavily 9 See https://www.mcecleanenergy.org/mce-sync/.
10 See https://mcecleanenergy.org/peak-flex-market/.
11 See https://mcecleanenergy.org/what-is-the-time-of-use-rate-plan/. 12 See https://www.mcecleanenergy.org/feed-in-tariff/.
13 See Agenda Item #06 from MCE’s December 2, 2021, Technical Committee Meeting, available at https://www.mcecleanenergy.org/wp-content/uploads/2021/11/MCE-Technical-Committee-Packet-December_2021.pdf. 30 weighted toward energy resources – dispatchable, shaped during non-solar or ramping periods, or otherwise – that complement competitively priced solar already under contract or pair new solar projects with storage technologies to avoid exacerbating midday over-supply. MCE may also engage in purchases from as-available renewable generation (e.g., wind) to the extent that such supply is competitively priced or otherwise provides electricity during time of day when existing supply commitments are currently lacking. Additionally, MCE is working with developers of its solar projects already under contract to add storage to those existing resources to increase the number of dispatchable resources in its portfolio. In regard to project location, MCE places the greatest value on locally-sited renewable generating and storage projects, particularly those located in its service area or within approximately 100 miles thereof. In general terms, the next highest preference related to resource selection are projects sited within the California Independent System Operator’s (“CAISO”) North of Path 15 Zone (generally, Northern California), followed by projects elsewhere in California, and lastly, out-of-state resources. This procurement strategy has led MCE to achieve its desired clean energy portfolio objectives as well as cost-competitive customer rates.
(iv) Description of How Energy Storage and Emerging Technologies are Addressed in Reliability and Diversity Planning.

Regarding new and emerging technologies, MCE has a particular interest in using offshore wind, long duration battery storage, and green hydrogen storage for building a carbon free portfolio for its customers and providing reliability to the grid. These technologies provide opportunities to shape MCE’s hourly portfolio to match the hourly demand. MCE has provided several letters of intent with the potential to get into long term agreements once the technology is commercially viable to developers of new and emerging technologies. MCE intends to continue this approach in the future.
31 IV.B.1. Forecasting for Increased Transportation Electrification A key component of the long-term load forecast includes the projections for transportation electrification load, the methodology for developing this forecast is described as follows:

Table 3: Transportation Electrification Load Forecast (2025-2035) Year 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 MCE
Annual EV
Load
Forecast
(GWh)
683 737 785 833 884 937 990 995 1,000 1,005 1,010
IV.B.2. Curtailment Frequency, Cost, and Forecasting
This Section responds to the questions presented in Section 4 of the ACR14 and describes MCE’s strategies and experience in managing the Agency’s exposure to negative pricing events, overgeneration, and economic curtailment for MCE’s region and portfolio of renewable resources. 14 ACR at 19-20.
32 IV.B.2.(a) Factors Having the Most Impact on the Projected Increases in Incidences of Overgeneration and Negative Market Price Hours Due in large part to the rapid increase in the amount of wind and solar generation coming online throughout the western United States, the CAISO Balancing Authority Area (“BAA”) has experienced an increasing frequency and magnitude of curtailment and negative pricing events.

The U.S. Energy Information Agency (“EIA”) estimates that as of March 2025, California has 41,262 MW of total installed solar capacity, with 18,706 MW of that total being behind-the meter solar.15 The CAISO reports that it has approximately 21,240 MW of utility-scale solar and 8,373 MW of utility-scale wind currently installed within its BAA.16 This capacity results in discrete periods where the majority of load in the CAISO is served by solar and wind resources. The monthly maximum load served by wind and solar in the CAISO has averaged 87.5% over the past 5 years (April 2020 to April 2025), and the monthly maximum load served by wind and solar exceeded 142%.17
To address the resulting instances of over-supply, the amount of curtailment of wind and solar in the CAISO has significantly increased each year from 2015 through 2022, totaling 187,000 MWh in 2015, 308,000 MWh in 2016, 358,000 MWh in 2017, 461,000 MWh in 2018, 961,000 MWh in 2019, 1,587,497 MWh in 2020, 1,504,803 in 2021, 2,449,248 in 2022 2,659,526 MWh in 2023, and 3,423,376 in 2024. As of June 12, 2025, the total curtailment of solar and wind year to date is 2,290,000 MWh. Curtailment is typically the highest during the months of March, April, 15 EIA, Electric Power Monthly, Table 6.2.B. Net Summer Capacity Using Primarily Renewable Energy Sources and by State, March 2025 and 2024 (Megawatts), available at:
https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=table_6_02_b.. 16 CAISO, What are we doing to green the grid?, updated April, 2024, at https://www.caiso.com/about/our-business/managing-the-evolving-grid 17 https://www.caiso.com/documents/monthly-renewables-performance-report-april-2025.html CAISO, Monthly Renewables Performance Report, April 2025, available at https://www.caiso.com/documents/monthlyrenewablesperformancereport-feb2024.html 33 and May when hydroelectric generation is historically at its highest and California load is at its lowest. Years in which there is an above-average snowpack results in higher-than-average hydroelectric generation which exacerbates renewable generation curtailment. The table below summarizes solar and wind curtailment from January 2025 through April 2025 Table 4: Summary of CAISO Solar and Wind Curtailment January-April 2025 2025 Data Wind Curtailment
(MWh)
Solar Curtailment
(MWh)
January 15,300 114,970
February 22,890 479,630
March 61,840 857,180
April 51,480 686,710
Total Curtailment 151,510 2,138,490
Curtailment % 2.02 % 13.68%
No. of Intervals Curtailed 14,841 16,728
Pct. of Intervals Curtailed 34.14 38.48
Annual Curtailment (MWh)
Wind Solar
2018 28,686 432,357
2019 43,557 921,684
2020 90,276 1,497,220
2021 78,477 1,426,326
2022 128,990 2,320,258
2023 150,604 2,508,916
2024 230,765 3,192,612
34 2025 (Partial Year*) 151,510 2,138,490
Annual Curtailment (% of Specific Generation)
2018 0.17% 1.56%
2019 0.27% 3.22%
2020 0.56% 4.99%
2021 0.41% 4.19%
2022 0.70% 6.26%
2023 0.72% 6.10%
2024 1.03% 6.29%
2025 (Partial Year*) 2.02% 13.68%
Average 0.55% 4.66%
Annual Curtailment (% of Load)
2018 0.013% 0.190%
2019 0.020% 0.420%
2020 0.041% 0.680%
2021 0.036% 0.650%
2022 0.057% 1.030%
2023 0.069% 1.148%
2024 0.103% 1.419%
2025 (Partial Year*) 0.227% 3.210%
Average 0.071% 1.093%
35 *Through April 2025
The CAISO notes that the majority of renewable resource curtailment is “a result of economic downward dispatch, rather than self-schedule curtailment,” and that “[m]ost renewable generation dispatched down in the ISO were solar resources, rather than wind, because solar resources typically bid more economic downward capacity than wind resources”.18 That means that curtailment happened in response to congestion and was mitigated by supply that was willing to reduce its output based on price signals from the CAISO market.

IV.B.2.(b). Written Description of Quantitative Analysis of Forecast of the Number of Hours Per Year of Negative Market Pricing for the Next 10 Years MCE’s scheduling coordinator agent, ZGlobal, has the capability to perform production cost analyses based on various input assumptions through 2035 to derive hourly market prices for energy and ancillary services. PLEXOS Integrated Energy Model is a commercial optimization engine that can simulate the economic commitment and dispatch used by the CAISO’s day-ahead market processes which simultaneously optimizes energy dispatch and ancillary services capacity 18 CAISO, 2020 Annual Report on Market Issues and Performance Report, published January 20, 2022, page 41, available at http://www.caiso.com/Documents/2020-Annual-Report-on-Market-Issues-and-Performance.pdf. 36 awards across the CAISO grid. In this way, the simulation will determine locational marginal prices and ancillary service marginal prices in the same manner the CAISO day-ahead market sets prices. ZGlobal has developed models using input assumptions that are based on common case inputs and planning guidelines from Western Electricity Coordinating Council, CAISO, Commission and CEC.

The key assumptions considered for the assessment included the impact of higher California renewable energy standards (60% RPS by 2030), planned gas-fired and nuclear generation retirements and adopted CEC demand forecasts which consider energy efficiency programs and increased behind-the-meter solar generation. Results are highly dependent upon input assumptions, primarily the level of new RPS generation, deployment of energy storage facilities, upgrades to CAISO-controlled transmission facilities and the ability to export energy from the CAISO to external balancing areas.

In California, electricity prices are typically set by gas-fired resources operating on the margin. However, as increasing supplies of renewable energy are added to the system, there are periods where marginal prices are being set by zero or even negatively-priced resources. Market prices have been trending downward, especially during seasons and periods of the day when loads are low and solar output is high with the influx of renewable energy resources. The modeling shows that during solar hours, prices are low during the middle of the day, driven by solar resources and their willingness to curtail and increasing in the morning and evening when gas-fired resources are needed to meet peak loads outside of the solar supply period. In short, prices as reflected by the CAISO’s duck curve are expected to continue, with the amplitude of the valley and ramps dictated by the amount of energy storage available to smooth out the net supply. 37 IV.B.2.(c) Experience, to Date, With Managing Exposure to Negative Market Prices and/or Lessons Learned from Other Retail Sellers in California MCE’s experience and process for managing exposure to negative market prices has been addressed above in Section IV.A.(iii).

Table 5: Summary of MCE RPS Resources Curtailment January-May 2025 Location Day-Ahead
Negative Prices
Real-Time
Negative Prices
Curtailment
(MWh)
Cost of
Curtailment ($)
South P26 -$10.79 -$16.59 1,711 $69,151
Fresno 1 -$36.83 -$43.49 79,701 $3,798,396
Fresno 2 -$18.78 -$24.52 997 $48,777
North P26 -$11.77 -$16.52 2,995 $110,174
Total -$22.41 85,404 $4,026,499
The Day-Ahead and Real-Time Negative Price columns represent averages of negative prices by RPS geographic area when prices are negative for solar hours for solar resources and all hours for wind resources. The prices are averages based on resources within the area. Curtailment MWh is the amount of energy that MCE RPS resources in the areas were curtailed from January 1 through May 31, 2025. “Cost of Curtailment” is the subsequent market cost of the curtailed energy.
38 IV.B.2.(e) An Overall Strategy for Managing the Overall Cost Impact of Increasing Incidences of Overgeneration and Negative Market Prices While curtailment is a viable renewable integration strategy that is generally more cost-effective than other options, there are potential negative consequences from excessive curtailment.

During its current and future renewable contracting efforts, MCE will pursue contract terms that recognize and limit the potential financial impacts of negative pricing and give MCE greater flexibility to direct economic curtailment, if this becomes necessary. 39 IV.B.2.(f)Contract Terms Included in RPS Contracts Intended to Reduce the Likelihood of Curtailment or Protect Against Negative Prices.

5. If alternative RPS-eligible products become necessary to meet MCE’s near-term portfolio objectives, MCE will consider these alternatives as appropriate. MCE’s preference for PCC1 RPS products is expected to minimize portfolio emission impacts that would otherwise accrue using Portfolio Content Category 2 (“PCC2”) and Portfolio Content Category 3 (“PCC3”) product options, both of which are ascribed emissions under California’s current emissions calculation methodology. While this approach is more costly it promotes the achievement of MCE’s GHG-related objectives. This noted, MCE may procure small quantities of RPS supply from clean and 40 specified PCC2 resources if unexpected delivery shortfalls are higher than expected retail sales and/or prevailing market conditions necessitate such purchases. MCE anticipates such purchases to be rare, if purchased at all. This flexibility to purchase PCC2 resources ensures that MCE can fulfill adopted portfolio commitments to its customers. MCE will advise the Commission if the Agency anticipates any deviations from the aforementioned resource preferences.

To support its RPS planning and procurement goals, MCE considers the following strategies:
● Joint Solicitations: Joint solicitations can expand the procurement opportunities available to a CCA, as well as provide procedural efficiencies, economies of scale, and overall cost savings for participating organizations. MCE is closely networked with other CCAs through its membership in the CalCCA, the trade organization representing California’s CCA sector, and regularly coordinates with other CCAs regarding prospective procurement opportunities and portfolio balancing activities. ● Purchases from Retail Sellers: Purchases of RPS-eligible renewable energy from other retail sellers can provide a cost-effective way of meeting short-term resource needs or filling in gaps in procurement while long-term projects are under development. MCE will evaluate solicitations offered by other retail sellers, as necessary. ● Sales Solicitations: As MCE continues to manage its growing portfolio of renewable resources, it will also consider administering sales solicitations (serving as a renewable energy seller) for the benefit of other retail sellers. Such solicitations are expected to be rare and relatively small in scale. MCE may also engage in bilateral sales discussions with certain retail sellers, including CCAs, if/when divesting relatively small amounts of surplus renewable energy supply is deemed necessary to rebalance MCE’s renewable portfolio 41 relative to internally established procurement targets. MCE has completed such processes in the past and expects to do so in the future as well. Selling excess renewable supply is an effective way for all LSEs to reduce unnecessary renewable energy expenses while providing valuable renewable energy products to other market participants. ● Optimizing Existing Procurement: As MCE considers its long-term resource needs, it may evaluate options in its future PPAspower purchase agreements to increase the output of existing generating facilities through technological upgrades. This can be accomplished by adding new capacity to an existing generator or by adding energy storage infrastructure to an existing renewable generator. Expanding existing facilities may provide additional generation at reduced costs with a lower risk of project failure because the need for distribution system upgrades and permitting may be minimized or eliminated. Adding energy storage infrastructure to an existing renewable generator enhances grid reliability and the value of electric energy produced by the generating facility. Such enhancements allow pre-storage energy delivery profiles to be shifted to: 1) better align MCE’s supply with customer demand; or 2) create more value for MCE customers by shifting electric energy deliveries to a time of day when market revenues (related to such energy deliveries) would be greater than normal. In terms of reliability impacts related to the addition of energy storage infrastructure, MCE expects that such enhancements would meaningfully increase the proportionate level of RA capacity that could be derived from an intermittent renewable generating resource. It is well documented that without such storage infrastructure, there will be reductions to the Net Qualifying Capacity (“NQC”) of intermittent renewable generating resources, resulting in very little capacity benefits from solar-only generating projects. In considering these sorts of enhancements, MCE will be 42 mindful of the need to coordinate with its resource owners/operators to evaluate potential planning constraints (e.g., generator interconnection processes and limitations) before determining that the addition of energy storage infrastructure at an existing generating facility would be a viable option.

MCE launched a its 2024 Open Season Request for Information (“RFI”) for Long-term Offers (“RFO”) on April 14, 2025.19 The results of the RFI will inform MCE’s approach to its typical Open Season solicitation process.March 4, 2024, and accepted offers through March 22, 2024.20 Open Season provides a competitive, objectively administered opportunity for qualified suppliers of various energy products (including renewable and storage technologies) to fulfill MCE’s future resource requirements and compliance obligations. Open Season is typically administered on an annual basis for purposes of soliciting offers for new-build renewable energy and storage resources and capacity that meet the procurement targets set forth in IRP.Integrated Resource Plan. The 20252024 Open Season will focuswas focused on soliciting resources that will provide the best value and best fit for MCE load shapes, in addition to supporting MCE’s compliance with regulatory procurement requirements. Under 2024 Open Season, MCE solicited offers for the following products: 1) PCC1-eligible Renewable Energy21, Green Attributes/RECs and capacity attributes; and 2) Renewable Energy Paired with Stand-Alone Energy Storage.22 As part of the Open Season solicitation process, MCE provides a Procedural Overview and Instructions document that describes the Open Season process, schedule, and requirements for 19 See https://www.mcecleanenergy.org/energy-procurement/. 20 See https://www.mcecleanenergy.org/energy-procurement/. 21 Solar PV projects submitted into MCE’s 2024 Open Season were required to be paired with integrated energy storage.
22MCE accepted both four-hour and long-duration (eight-hours or more) storage, as well as any other technology type.
43 submitting a conforming offer. MCE also provides an offer form and term sheets that must be submitted along with the offer.

During this year’s RFI, MCE sought information from qualified suppliers of renewable energy, energy storage products and RA to inform MCE’s formal long-term offer solicitation in 2025. MCE’s procurement team launched an RFI as an initial step in its long-term procurement efforts in 2025. MCE believed that this new approach would streamline procurement efforts for all participants. MCE sought information for prospective full-toll agreements (all applicable products) with a minimum contract term length of RFO, offerors could submit offers at least five (5) years from Renewable Energy (PCC1-eligible) projects, Renewable Energy Paired with Energy Storage projects, and Standalone Energy Storage projects. Projects were to be no less than 5 MW for 24x7 load profiles or no less than 25 MW for intermittent resources. Beyond these categories, responses were not limited in any other respect. Due to numerous headwinds in the market for grid-scale projects, including interconnection delays and process reforms, permitting challenges, and federal tax credit and tariff uncertainty, MCE sought a new approach to its long-term procurement in 2025. The procurement team believed a streamlined RFI process would provide an indication of the current landscape for projects in all stages of development. The Procurement team worked closely with MCE’s Public Affairs team, leveraged external stakeholders, including CalCCA, and communicated with an extensive network of developers to draw participation in the RFI. MCE will continue to evaluate the RFI results and may pursue a formal Request for Offers (“RFO”) from qualified respondents.
time between March 4, 2024 through March 22, 2024 (“Offer Window”). When an offer is received, MCE first reviews an offer for completeness relative to the RFO eligibility criteria. MCE then conducts a quantitative analysis focused on the value of each conforming offer, in addition to 44 a qualitative review evaluating non-quantitative offer details, like interconnection status, in more depth. MCE selects the strongest offers on a rolling basis, in parallel to completing evaluations of other offers as they are submitted. To ensure that favorable opportunities are not “lost” to other buyers, MCE works with the 3rd party to enter into an Exclusivity Agreement once an offer has been short-listed.

Once an Exclusivity Agreement is executed, Staff will begin contract negotiations with the shortlisted projects. The resulting PPAsPower Purchase Agreement(s) (“PPA”) and Energy Storage Agreement(s) (“ESA”) are reviewed by MCE’s Executive Management team before review and approval by MCE’s Board. of directors (Board). Contract execution occurs after the agreements are approved by the Board.

MCE also considers allocations from PG&E in its portfolio optimization. Through the Power Charge Indifference Adjustment (“PCIA”),, MCE customers (and other CCA and Direct Access customers) are required to pay their share of the above-market costs associated with PG&E’s legacy resources such as its large hydroelectric fleet, PG&E’s nuclear power plant, Diablo Canyon, and many PG&E PPAs including RPS PPAs. As nearly half of PG&E’s customer load has departed for other LSEs, it has resulted in PG&E having excess resources in its portfolio.

Accordingly, the Commission directed PG&E to offer a proportionate share allocation of output from hydroelectric and nuclear, GHG-free, resources at no additional cost on a voluntary basis to CCAs and Direct Access providers whose customers pay the PCIA for the years 2019 and 2020. (“Interim Allocation” The Interim Allocation was extended into 2021 by Resolution E-5111, in which the Commission also authorized PG&E to extend the interim approach to GHG-Free resources through December 31, 2023.). In Decision (“D.”) 23-06-06 the Commission modified the PCIA methodology by allowing PG&E to elect to either offer an allocation of large hydro 45 GHG-Free attributes or to retain the attributes and value them at a new market price benchmark.

In Advice Letter 7005-E, PG&E notified LSEs of its intent to offer large hydro allocations for 2024, and in its 2025 Energy Resource Recovery Application PG&E notified parties of its intent to offer large hydro allocations for the 2025-2027 period as well. As MCE’s Board in late 2024, accepted the hydro allocations as well as 2025has previously elected not to take nuclear allocations. from PG&E to align with its policy of no resource-specific nuclear transactions, MCE will usehas only accepted PG&E’s hydroelectric allocations since 2020 and uses these allocations in meeting its internally adopted GHG-free targets. Additionally, MCE structured its Light Green portfolio to be approximately 95% GHG-free starting in 2023, 23 , subject to market and/or
regulatory changes. To structure such a clean Light Green portfolio by 2023, MCE procured three products: (1) RPS-eligible renewable energy; (2) large hydroelectric energy; and (3) Asset Controlling Supplier energy, the vast majority of which is attributable to large hydroelectric generating resources. To ensure grid reliability, MCE’s contracting goals include 475 MW of stand-alone energy storage to be online by 20302029, and to have approximately 153 MW of new energy storage paired with solar resources online by 2030.24 Disadvantaged Community Solar Green Tariff: In 2021, MCE launched its first solicitation for the Green Access (“Disadvantage Community – Green Tariff” or “DAC-GT”) and Community Solar Connection (“DAC-CSGT”) procurement process (“2021 Green Tariff”). The purpose of MCE’s 2021 Green Tariff was to fulfill the requirements of Assembly Bill (“AB”) 327, CPUC Decision (“D..”) 18-06-027, D.18-10-007, and Resolution E-4999 (collectively the “Green Tariff 23 MCE’s Operational Integrated Resource Plan, https://www.mcecleanenergy.org/wp-content/uploads/2022/11/MCE-Operational-Integrated-Resource-Plan_2023.pdf. 24 MCE’s 2022 CPUC Integrated Resource Plan, https://www.mcecleanenergy.org/wp-content/uploads/2022/11/MCE-2022-Integrated-Resource-Plan_11012022.pdf. 46 policy”). The Green Tariff policy is intended to promote the installation of renewable generation among residential customers in disadvantaged communities (“DACs”). MCE executed two contracts for the DAC-GT program. To comply with the Green Tariff policy, MCE has to procure under two programs: 1) Green Access and 2) Community Solar Connection. MCE fulfilled the requirements of the Green Access program through the selected projects from the 2021 solicitation.

MCE held annual solicitations for the Community Solar Connection program in 2022 and 2023 and received no offers. MCE then opened the Community Solar Connection solicitation in 2024 on an open until filled basis with no offers received. On May 30, 2024, the CPUC issued D.24-05- 065, which made several modifications to the DAC-GT program, including adopting changes to the cost cap for the program, and closingcloses the Community Solar Connection program, rolling unused capacity into the DAC-GT program. MCE is currently evaluating the ruling and will likely release a solicitation addressing both these elements. for the additional volume made available to the DAC-GT program in the Decision.

On June 24, 2021, the Commission adopted D.21-06-035, which directed all retail sellers to collectively procure 11,500 MW of new NQC, including LLTlong-lead-time resources (“LLT resources”) to come online between 2023 and 2026. This decision assigned each retail seller a specific procurement responsibility based on its share of peak demand. In February 2023, the Commission issued D.23-02-040, which supplemented the initial Mid-Time Reliability (“MTR”) order to require LSEs to procure an additional 4,000 MW of NQC and pushing out the online date for LLT resources to 2028. MCE’s total obligation, resulting from these two CPUC decisions, is 454 MW of NQC by June 1, 2028. MCE’s 454 MW requirement includes 72 MW of NQC from dispatchable, zero-emitting capacity, required to be online by June 1, 2025. As part of its 454 MW requirement, MCE must also procure at least 58 MW of LLT resources, including (1) 29 NQC 47 MW from long duration storage resources by June 1, 2028; and (2) 29 NQC MW from firm, non-fossil fueled baseload generating resources by June 1, 2028. 25 MCE plans to meet its MTR
obligations using a diverse set of resource technologies, some of which will be RPS-eligible. MCE has negotiated a number of Energy Storage Agreements (“ESAs”) and PPAs to meet its MTR obligations, and hasto the extent MCE has already executed agreements for RPS-eligible resources related to the MTR.
26 As discussed in Section V below, pursuant to the Commission’s initial MTR order, MCE has eight executed contracts for projects under development that will be used to meet MTR mandates: Daggett, Golden Fields, Geysers, Humboldt House, Strauss Wind, Key, Cormorant, and Corby. MCE’s RNS, Project Development Status, and Cost Quantification templates have also been updated to incorporate these eight projects.

Generally, the MTR decisions are alignedin alignment with MCE’s internally adopted contracting goals, which are highlighted above. As noted above, MCE providedplans to provide approximately 99% GHG-free and 69% renewable energy through its Light Green base product in 2024, as shown in MCE’s 2024 2023. While MCE is still in the process of preparing its final 2023 Power Source Disclosure (“PSD”) Report., which currently must be delivered to the California Energy Commission (“CEC”) no later than July 29, 2024, the current draft reporting template for MCE Light Green service suggests that the organization will have achieved its lowest portfolio emission factor ever while also fulfilling its 60% renewable energy delivery target for such customers. Should the actual emission factor and/or renewable content reflected in the final reporting template differ from the previously noted statistics, MCE will accordingly advise the Commission in its Final 2024 RPS Procurement Plan. All other MCE customers, including those 25 Pursuant to D.23-02-040, the Commission changed the required online dates for LLT resources from 2026 to 2028.
26 See Renewable Net Short Template Row Fb.
48 participating in the Deep Green, Local Sol, and Green Access service options, received supply reflecting 100% renewable and zero carbon emissions in 2024.2023.

MCE intends to use RPS-eligible resources acquired for the MTR procurement mandates to fill open positions relative to MCE’s internal RPS goal.27 MCE will continue to use procurement strategies such as joint contracting efforts, buying from other retail sellers, and optimizing existing procurement, as described earlier in this section, to meet the MTR procurement mandates and MCE’s internal goals for RPS at the lowest cost to its customers.

IV.C.1 Conformance with the IRP Proceeding
The resources identified in this RPS Procurement Plan are consistent with the resources MCE expects to identify in MCE’s 2025 IRP, which is currently required to be submitted to the Commission for certification by November 1, 2025.28 MCE’s RPS Procurement Plan is also consistent with the biannual MTR updates provided to the Commission addressing MCE’s progress towards meeting procurement requirements under D.21-06-035 and D.23-02-040.29 As required by the ACR,30 specifically, Table 6below describes how MCE’s 2025 RPS Procurement Plan conforms with the determinations made in the IRP Proceedings (R.16-02-007 and R.20-05- 003) and highlights the interrelationships of its RPS and IRP planning processes. The following table reflects MCE’s current updates, as reflected in this RPS Procurement Plan, regarding RPS alignment with the 2024-2026 IRP process.
27 See Row Ga of the Renewable New Short Template.
28 While Commission decision indicates that LSEs are to submit 2025 IRP to the Commission by November 1, 2025, Energy Division indicated via email on June 5, 2025 that the IRP timeline will be delayed.
29 Since filing its 2022 Compliance IRP, MCE has filed six biannual MTR update filings on February 1, 2023, August 1, 2023, December 1, 2023, June 3, 2024, December 2, 2024, and June 2, 2025 respectively.
30 ACR at 21-22.
49 Table 6: RPS Alignment in MCE’s IRP
IRP Section
Subsection
RPS Alignment in IRP
III. Study Results
A. Conforming and
Alternative
Portfolios
Retail sellers should explain how the RPS resources they plan to procure, outlined in their RPS Plan, will align with each of their Conforming Portfolios being developed in their IRP Plans for Commission approval and certification. This explanation should include:

1. Existing RPS resources
that the retail seller owns
or contracts.

2. Existing RPS resources
that the retail seller plans
to contract with in the
future.

3. New RPS resources that
the retail seller plans to
invest in.

4. New and existing
resources that will be used
to meet Mid-Term
Reliability obligations
adopted in D.21-06-035
and the supplemental
procurement ordered in
D.23-02-040.

MCE’s portfolio mix and planned
procurement met the requirements of the
2022 IRP Preferred Conforming Portfolio
(“PCP”) in the last IRP cycle and met
MCE’s compliance and internal
obligations and targets. Looking forward
to the upcoming 2025 IRP, MCE
anticipates that its planned procurement of
a diverse set of renewable resources, as
represented in its 2022 PCP and as
supplemented and complemented with
additional near-, mid-, and long-term
procurement, will meet the Commission’s
mandated emissions targets and reliability
metrics, including the balanced and
diverse set of resources identified in the
most recent (2023) preferred system plan
adopted by the Commission. MCE's PCP
procured to the lower emissions target that
was adopted in the 2023 PSP. As such,
MCE expects that its portfolio will
50 comply with the emissions metrics of the
current Preferred System Plan and the
emissions metrics in the upcoming IRP
cycle. However, MCE notes that until
official guidance and requirements for the
2025 IRP cycle are issued by the
Commission, MCE cannot state with
certainty what its optimal long-term
procurement plan will be. To remain
resilient and flexible, MCE has not set a
specific ratio on the characteristics or type
of resources for its planned procurement.

The right balance will depend on multiple
factors including but not limited to;
• Specific and final IRP requirements;
• Availability of eligible resource types
on the market;
• Project development timelines;
• Deliverability of available resources
for contracting;
• Price and affordability;
• Location and congestion analysis; and
• MCE Portfolio fit.
• For reference, a description MCE’s
PCP is as follows:
● MCE’s PCP achieves an overall
portfolio GHG target below MCE’s
assigned share of the 2030 and 2035
emissions under both the 30 million
metric tons (“MMT”) and 25 MMT
scenarios.
● Using the CPUC’s embedded
assumptions in the 25 MMT portfolio,
MCE’s emissions registered at 0.493
MMT relative to MCE’s assigned
share of 0.640 MMT in 2030 and

0.492 MMT relative to 0.504 MMT in
2035.
● MCE’s PCP assumed the use of RPS
resources that were reflected in
51 MCE’s supply portfolio at the time of
the 2022 IRP filing.
● The planned RPS-eligible resources
reflected in MCE’s PCP included: 109
MW geothermal; 356 MW wind
(consisting of in-state, out-of-state,
and off-shore); and 222 MW solar
o Of the aforementioned PCP
resources, MCE anticipated the
following new RPS-eligible
capacity additions: new hybrid
resources totaling 212 MW solar/
153 MW battery storage, 109
MW of geothermal, and new wind
resources totaling 265 MWs.
● MCE also continues to procure and
develop projects (both renewable
generation paired with storage and
stand-alone storage) to meet its MTR
requirements pursuant to D.21-06-035
and D.23-02-040 (MCE was assigned
332 MW of incremental Net
Qualifying Capacity to meet its share
of the state’s MTR need pursuant to
D.21-06-035 and was assigned an
additional 122 MW of incremental
NQC to be online by 2027 pursuant to
D.23-02-040). MCE continues to
actively procure to meet the initial
MTR need, the supplemental MTR
need, and RPS-related needs in
compliance with the mandated
timelines. All of this procurement
contributes towards MCE’s MTR- and
IRP-related needs, and much, but not
all, of the procurement will contribute
towards MCE’s RPS-related
requirements. At the time of this
filing, MCE’s existing executed MTR
agreements or new build RPS-eligible
procurement include the following
incremental capacity amounts: 27 MW
52 of nameplate geothermal capacity; 100
MW nameplate solar paired with 92
MW of nameplate storage; and 110
MW of nameplate solar paired with 60
MW of nameplate storage, 93.35 MW
of nameplate wind capacity, and 110
MW of nameplate solar paired with
110 MW of storage. Although not
MTR-eligible, MCE has also procured
and brought online 100 MW of
energy-only solar capacity from a
new-build solar facility. All of the
referenced procurement contributes
towards the diverse set of resources
indicated in MCE’s 2022 PCP, which
portfolio will continue to be revised
and supplemented to account for
market conditions, regulatory
requirements, and internal portfolio
optimization needs.
● MCE is also taking action via its
annual solicitation processes to
identify additional projects that
contribute towards MCE’s MTR, RPS,
and general IRP needs through formal
RFIs and RFOs as well as pursuing
bilateral opportunities with project
developers as described in more detail
in Section IV.C, above. MCE expects
that some of this procurement will be
eligible to contribute towards MCE’s
RPS needs; all of this procurement is
expected to contribute towards MCE’s
existing MTR needs and existing and
future IRP procurement obligations to
support reliability and GHG reduction
efforts. Through administration of
MCE’s RFI procurement process,
MCE is seeking to reduce outstanding
resource needs required to meet
portfolio specifications reflected in its
PCP, MTR requirements, as well as
any other internal and state-mandated
RPS or reliability procurement targets.
53 To the extent additional resources are
needed, MCE is conducting
supplemental, smaller solicitations and
pursuing bilateral negotiations.
● Separate from, and predating the RFI,
MCE is also pursuing various new-build projects for wind capacity, additional geothermal capacity, and
co-located solar and storage capacity
that MCE expects to be under contact
within the year or soon thereafter.
● In addition to the more formal
solicitation processes, MCE also
solicits offers for short-term PCC1
renewable energy purchases/sales for
annual portfolio balancing.

Any IV. Action
Plan
A. Proposed
Activities
Retail sellers should describe how they propose to use RPS resources to implement both Conforming Portfolios. Narratives should include:

1. Proposed RPS
procurement activities as
required by Commission
decision or mandated
procurement.

2. Procurement plans,
potential barriers, and
resource viability for each
new RPS resource
identified.

As described above in the Study Results
section, there is significant overlap among
MCE’s RPS-related procurement, IRP-related procurement, and MTR-related procurement. MCE has contracted for
three co-located resources, which are
expected to provide additional RPS- and
54 MTR-eligible incremental capacity (one of
which is online, the other two resources
are expected to achieve commercial
operation in August 2025 and April 2031,
respectively).

MCE’s prior RPS procurement plan also
indicated MCE had four contracts for
geothermal capacity (3 of which were
incremental, new build capacity; 1 is for
100 MW of existing geothermal capacity
for a 10-year delivery period starting in
2027). As of this filing, and as has been
previously reported to the Commission in
prior RPS- or MTR-related filings, due to
contract failure of one of the incremental
geothermal projects, MCE now has three
recently procured geothermal projects
under contract (2 of which are incremental
geothermal capacity eligible to count
towards MTR requirements). All of the
aforementioned geothermal procurement
is under long-term contract. Of note, one
of the aforementioned incremental
projects (representing 7 MW of
geothermal capacity) achieved
commercial operation in June 2025 and is
actively contributing towards MCE’s
reliability, emissions, and RPS needs. The
other incremental geothermal project
(representing 20 MW of nameplate
capacity) has encountered a number of
material delays due to interconnection and
permitting. These delays will require
material changes to critical contract
milestones, including construction start
and commercial operation, both of which
MCE expects to be achieved before 2030.

For more detailed descriptions of MCE’s
MTR procurement, please refer to MCE’s
biannual MTR update filings, the latest of
which was filed on June 2, 2025.

MCE is also actively pursuing various
new-build projects for wind capacity,
additional geothermal capacity, and co-
55 located solar and storage capacity, as
mentioned in the Study Results Section
above and throughout this RPS Plan.

MCE expects these resources to be under
contact within the year or soon thereafter.

1. The type of solicitation.

2. The timeline for each
solicitation.

3. Desired online dates.

4. Other relevant
procurement planning
information, such as
solicitation goals and
objectives.

Responsive to current portfolio needs, and
in anticipation of future needs, MCE’s
current RFI process is specifically
targeting PCC 1-eligible renewable energy
generating facilities that may be paired
with energy storage and/or renewable
baseload capacity. MCE is currently
evaluating responses to this RFI and
expects to launch a subsequent RFO
and/or commence discussions with
potential project developers bilaterally to
try to secure projects that can meet MCE’s
current and anticipated RPS, IRP, and
MTR needs. In addition to the more
formal solicitation processes, MCE also
solicits offers for short term PCC1
56 renewable energy purchases/sales for
annual portfolio balancing.

1. Key market, regulatory,
financial, or other
resource viability barriers
or risks associated with
the RPS resources coming
online in both retail
sellers’ Preferred
Portfolios.

2. Key risks associated
with the potential
retirement of existing RPS
resources on which the
retail seller intends to rely
in the future.

MCE notes that even though a balanced,
diverse RPS portfolio is desirable, the
limited resource availability and lead time
required for some technology types will
necessitate planning flexibility. While
MCE has a highly successful track record
of contracting with new-build renewable
resources, there is always a risk of project
failure due to market and regulatory
conditions beyond MCE’s control. Of
increasing concern to MCE is the
backlogged interconnection queue and
delays in processing the numbers of
applications for interconnection studies
and deliverability. Restrictions and
uncertainty on this front increase risk and
uncertainty for LSEs and can ultimately
present a material barrier to LSEs bringing
on new RPS resources that have sufficient
deliverability to meet RPS program and
reliability needs. Importantly,
transmission and interconnection issues
not only affect the viability of projects at
the outset, but impact the on-going
economics of projects once the generation
is online – this is particularly relevant for
non-dispatchable renewable projects that
are subject to curtailment due to
insufficient transmission. Adding to this
constraint are lingering supply chain
issues and permitting delays that impact
timely development and interconnection
of new resources.

MCE also notes that potential changes to
federal tax policy threaten to materially
impact renewable energy development in
57 California – the full impacts of which are
yet to be determined.

IV.C.2. ResponseB. Responsive to Local and Regional Policies (i) Responsiveness to Policies of MCE Governing Board
MCE is a local governmental agency that is subject to the control of its governing board and is directly accountable to the community that it serves. MCE strongly supports and is committed to meeting the state’s GHG reduction and renewable procurement goals. As a member of CalCCA, MCE actively supported the passage of SB 100 (2018) and has fully incorporated the procurement requirements of the state’s RPS program into its overall procurement strategy.

Furthermore, MCE’s existing contractual commitments have secured the significant majority of its renewable energy requirements. Existing contracts continue to address the majority of MCE’s renewable energy needs throughout the planning period addressed in this RPS Procurement Plan and are expected to account for 97129% of statutorily mandated long-term renewable energy procurement requirements in 2035.2034 and 94% of total RPS procurement requirements in that year. MCE’s planning and procurement process remains ongoing, which is expected to result in additional renewable energy acquisition, the substantial majority of which will be secured via long-term contracts.

Additionally, MCE policy, established by MCE’s founding documents and directed on an 58 ongoing basis by MCE’s governing board, guides development of the resource plan and related procurement activities. MCE’s key resource planning policies are as follows:
● Reduce GHG emissions and other pollutants within the electric power sector through increased use of renewable, GHG-free, and low-GHG energy resources; ● Maintain competitiveaffordable electric rates and increase control over energy costs through management of a diversified resource portfolio; ● Benefit the localarea’s economy by offering competitive electricity rates and customer programs, and investingthough investments in local infrastructure, energy, and workforce-development programs within MCE’s service area; ● Help customers reduce energy consumption and electric bills by supporting and administering enhanced customer energy efficiency, cost effective distributed generation, and, other demand-side programs;
● Pursue load and generation shaping to help reduce grid reliance on fossil power, manage costs, and promote reliability.
● Enhance system reliability through investments in supply- and demand-side resources; ● Actively monitor and manage operating risks to promote MCE’s continued financial strength and stability; and
● Support supplier and workforce diversity as permitted by law.

To enable MCE to meet its resource planning objectives, MCE’s governing board has formally adopted the following policies related to resource planning and procurement:
59 (1) MCE’s Sustainable Workforce and Diversity Policy:31 MCE is committed to supporting sustained and fairly compensated local job opportunities through participation in the energy industry. To the extent allowed by state law, MCE seeks to create market incentives and partnerships to encourage diversity and a sustainable workforce through its support for:
● Fair compensation in direct hiring, renewable development projects, customer programs, internships, and procurement services;
● Development of locally generated renewable energy within MCE’sthe MCE service area;
● Direct use of union members from multiple trades;
● Quality training, apprenticeship, and pre-apprenticeship programs; ● Direct use of businesses local to MCE’sthe MCE service area; ● Development of California-based job opportunities;
● Business and workforce initiatives located in low-income and disadvantaged communities;
● Direct use of Disabled Veteran-owned Business Enterprises and LGBT-owned Business Enterprises;
● Direct use of green and sustainable businesses; and
● Use of direct hiring practices that promote diversity in the workplace. (2) MCE’s Energy Risk Management Policy:32 MCE manages its energy resources and 31 See Attachment A to Agenda Item #7 from MCE’s November 16, 2017 Board Meeting, available at https://www.mcecleanenergy.org/wp-content/uploads/2020/05/MCE-Board-Meeting-Packet-November_2017.pdf. 32 See Attachment to Agenda Item #7 from MCE’s May 2, 2019, Technical Committee Meeting, available at https://www.mcecleanenergy.org/wp-content/uploads/2020/01/MCE-Technical-Committee-Packet-May_2019.pdf. 60 transactions for the purpose of providing its customers with low-cost renewable, carbon free and other energy, while at the same time minimizing risks. MCE procures energy and RA consistent with its Energy Risk Management Policy, which has been developed to ensure that MCE achieves its mission and adheres to policies established by the MCE Board of Directors, power supply and related contract commitments, good utility practice, and all applicable laws and regulations.
(ii) Responsiveness to Regional Policies
MCE is governed by a 3634-member Board of Directors comprised of elected Councilmembers or Supervisors from its 38 member communities and is committed to benefiting its service area’s economy through investments in local infrastructure and energy programs.

IV.B.1. Long-term Procurement
MCE has been committed to supporting new, California-based renewable resource 61 development since its inception, and has supported numerous generating assets via execution of long-term contracts. MCE has already executed long-term renewable contracts that are expected to yield approximately 105% of its total RPS/statutory renewable energy requirements (or 162% of MCE’s expected RPS-related long-term renewable energy requirements) in 2024. Further, most of the renewable energy supply solicited under MCE’s Open Season is intended for projects with proposed delivery terms between ten and twenty years, which bolsters MCE’s proportionate use of long-term renewable energy over time. The table below relates projected deliveries under MCE’s existing long-term RPS supply contracts to interim annual RPS procurement targets and related long-term contracting requirements.

Table 2: Projected RPS Deliveries
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
Proportionate Long-Term RPS Purchases
Relative to Interim
Annual Statutory
Procurement Mandate 105% 113% 111% 120% 126% 121% 115% 109% 107% 96% 94% Proportionate Long-Term RPS Purchases
Relative to Interim
Annual Statutory Long-Term Contracting
Requirement 162% 174% 171% 184% 194% 187% 176% 163% 156% 137% 129% It is clear that MCE’s substantial, ongoing commitment to long-term RPS contracting has created significant projected long-term RPS surpluses. As a result of such surpluses, there is virtually no risk of MCE falling short of this aspect of the RPS compliance program.

Figure 1 also depicts the relationship between California’s currently effective long-term RPS contracting mandates and projected deliveries related to MCE’s existing long-term RPS contracts, for calendar years 2024 through 2034. The rightmost bar in each grouping reflects 62 California’s 65 percent RPS contracting mandate as 100 percent of the total long-term contracting requirement. MCE has included two additional bars in each grouping:
1) An unadjusted projection of MCE’s expected annual long-term contract deliveries, relative to the 65 percent mandate. This bar represents the proportionate relationship between MCE’s long-term contract deliveries and the statewide procurement mandate. For example, MCE projects that it will surpass the state’s long-term contracting requirement by 62 percent in 2024 and is not expecting to fall below 100 percent of its long-term contracting requirement through 2034; and
2) An adjusted projection of MCE’s expected annual long-term contract deliveries relative to the 65 percent procurement mandate. This bar represents the proportionate relationship between MCE’s long-term contract deliveries (including an annual reduction in such deliveries equivalent to MCE’s established Minimum Margin of Over Procurement (MMoP), which reflects the potential impacts of delivery shortfalls related to resources intermittency, delays in commercial operation, resource curtailment, supply chain issues, and/or other operational issues) and the statewide mandate. MCE believes that this scenario represents a relatively extreme stress case. Nonetheless, MCE would expect to meet or exceed California’s long-term contracting mandate through 2034. 63 Figure 1: MCE’s Projected Long-Term RPS Contracting Progress: 2024-2034 Note that the data underlying this bar chart has been compiled annually, which means that the noted percentages do not reflect the additional compliance flexibility related to California’s multi-year compliance periods. For example, if MCE exceeds the long-term procurement mandate by 62% in 2024, it could absorb meaningful delivery shortfalls in the other years encompassing Compliance Period 4 before any compliance deficits arise. Unadjusted projections of MCE’s long-term contracting progress suggest that MCE is expected to exceed applicable mandates through the current planning period (2034). Likewise, adjusted projections also suggest that MCE will similarly exceed applicable mandates, even under a relatively extreme stress case such as the one reflected in the previous bar chart. MCE expects to engage in additional long-term contract efforts, which will further increase its long-term RPS positions as well as the compliance buffer already in place.
64 IV.C. Portfolio Diversity and Reliability
As part of MCE’s forecasting and procurement processes, MCE also considers the deliverability characteristics of its resources including the expected delivery profile, available capacity and dispatchability attributes, if any, associated with each of its generating resource and/or supply agreements and reviews the respective risks associated with short- and long-term purchases. These efforts lead to a more diverse resource mix, address grid integration issues, and provide value to MCE’s member communities, including reduced costs and support in achieving planned procurement objectives for the period addressed in this RPS Procurement Plan. A quantitative description of MCE’s forecast is attached in Appendix C.

MCE is interested in emerging and viable technologies to meet the state’s reliability needs. MCE’s commitment to innovation and the advancement of renewable technologies continues to drive strategic opportunities for the inclusion of emerging technologies within its supply portfolio. The extent to which such technologies will be successful in mitigating conditions of over-supply, production variability and misalignments between energy production and customer use will be monitored over time to ensure that such contractual commitments are promoting desired outcomes.

In 2020, MCE also implemented an “equivalent carbon-free” portfolio metric, which considers the total emissions associated with each supply source relative to a target annual 65 emission factor for its entire supply portfolio. For example, MCE’s 95% carbon-free equivalent metric in 2023 allowed an overall portfolio emission factor equal to 5% of the California Air Resources Board’s (“CARB”) assigned emission factor for energy imports and system power, which is currently set at 0.428 metric tons of carbon dioxide equivalent per megawatt hour (“MT CO2e”). Expressed differently, the 95% carbon-free equivalent metric limited, on a voluntary basis, MCE’s emissions to an overall portfolio emission factor of 0.021 MT CO2e. As reflected in its current draft 2023 PSD report for Light Green service33, MCE’s 2023 emission factor of 0.002 MT CO2e was below the organization’s 95% carbon-free equivalent emission target (reflecting an approximate 99% carbon-free equivalency for the Light Green portfolio. The emission factor for Deep Green, Local Sol and Green Access service, as reflected in the respective 2023 PSD reports for each retail service offering, was zero.

As certain renewable generating technologies are known to have relatively low levels of emissions, such as certain geothermal generating technologies, MCE’s equivalent carbon-free metric captures such impacts, along with any other use of carbon-emitting supply, including system power and CARB-certified Asset Controlling Supply, to derive its proportionate use of carbon-free generation. To the extent that MCE’s energy needs are not fulfilled using renewable or other GHG-free generating resources, it should be assumed that such supply will be sourced from conventional energy sources, such as natural gas generating technologies or system power purchases. MCE also plans to maintain its carbon-free equivalent metric at 95% of total supply in 2024 and beyond, meaning it will be further constrained in utilizing any carbon-emitting sources, 33 The due date for California’s 2023 Power Source Disclosure Report is July 29, 2024. MCE is still finalizing the report for Light Green service and will update the Commission (within its Final 2024 RPS Procurement Plan) if there are any material deviations from the information presented herein.
66 including certain renewable generating technologies. As such, MCE will continue to creatively address the exercise of resource planning and portfolio composition to meet or exceed the aforementioned carbon-free equivalency metric.

A key component of this process relates to the analysis and consideration of MCE’s forward load obligations and existing supply commitments with the objectives of closely balancing supply and demand, cost/rate stability and overall budgetary impacts, while leaving some flexibility to take advantage of market opportunities and/or technological improvements that may arise over time. MCE’s long-term load forecast is a projection of the energy (reflected in MWh) that its customers will consume annually. MCE’s long-term load forecast is driven primarily by the number and types of customers that MCE expects to serve, in conjunction with weather projections. Hourly class-specific load profiles are then used to break down the monthly energy forecast into more granular time-of-use and peak demand values. MCE’s long-term load forecast also incorporates the load-modifying effects of electric vehicles, behind-the-meter solar and/or storage (via net energy metering), and energy efficiency.

A key component of the long-term load forecast includes the projections for transportation electrification load, the methodology for developing this forecast is described as follows:

MCE’s load forecast is adjusted for expected increases due to electric vehicle (“EV”) adoption. In order to estimate the impact of EV adoption on MCE’s load forecast, MCE utilizes 67 the CEC’s Integrated Energy Policy Report as the basis for the estimates. MCE utilizes the state’s mid-demand scenario, adjusting the forecasted EV load based upon two factors: 1) EV adoption rates within MCE’s service territory and 2) Participation rates within MCE’s service territory. CA Department of Motor Vehicle registration data is utilized to estimate the territory’s share of the state’s forecasted EV load growth, and internal customer data sources are utilized to adjust for MCE participation rates. MCE’s EV load growth forecast does not segment by vehicle types, but rather adjusts the state’s total EV load based upon penetration levels.

MCE monitors its open positions separately for each renewable generating technology as well as GHG-free resources, conventional resources, and its aggregate supply portfolio. MCE maintains portfolio coverage targets of up to 100% of expected customer energy requirements in the near-term (0 to 2 years), and typically leaves gradually larger open positions in the mid- to long-term, consistent with generally accepted industry practices. However, those larger open positions are continuously monitored for weather, market changes and resource availabilities, and filled in a non-linear fashion as determined by MCE management. For example, MCE may fill residual summer positions ahead of the spring season or through procurements administered during the previous calendar year.

MCE prefers zero emission generating technologies, but within this preference MCE is largely technology-agnostic, subject to the previously discussed carbon-free equivalency metric.34 MCE’s supply preferences are intended to exhibit diversity across a broad range of renewable technologies that will deliver energy in a profile that is generally consistent with MCE’s anticipated load shape. MCE is aware that significant use of intermittent renewable generating 34 As mentioned above, MCE has a policy of not pursuing resource-specific nuclear power purchases.
68 technologies has the potential to create misalignments between customer energy consumption and related power production; however, MCE regularly evaluates customer usage in light of expected renewable deliveries to reduce such risks and inform future procurement decisions. Furthermore, MCE continues to consider procurement opportunities with renewable generating facilities that will utilize storage technology, which can materially re-shape the typical delivery profile associated with intermittent renewable generating assets, providing the opportunity for MCE to more accurately balance supply and changing customer demand, particularly due to the potential expansion of transportation electrification. MCE is also considering stand-alone energy storage opportunities to “recontour” purchased energy volumes in a manner that better matches changing customer usage patterns. MCE has determined that such projects are comparatively costly (due to infrastructure costs and, in the case of battery storage projects, losses stemming from the common charge/discharge cycle of such projects). In 2024, approximately 10.8 percent of MCE's total retail sales were expected to come from transportation electrification load in MCE's service territory, and this number is projected to increase to 17.4 percent of MCE's total retail sales in 2034. MCE currently offers a managed EV charging app, MCE Sync, which helps customers automate EV charging and shift consumption away from peak periods.35 Additionally, MCE offers several programs to manage its load shapes and better align MCE’s supply resources with hourly demand.

These programs include, but are not limited to: MCE’s Peak FLEXmarket,36 Time of Use (“TOU”) rates,37 and MCE’s revised Feed-In-Tariff (“FIT”) Plus program,38 that requires the addition of storage equal to 180% of the generator’s nameplate capacity, and enables generation to be shifted 35 See https://www.mcecleanenergy.org/mce-sync/.
36 See https://mcecleanenergy.org/peak-flex-market/.
37 See https://mcecleanenergy.org/what-is-the-time-of-use-rate-plan/. 38 See https://www.mcecleanenergy.org/feed-in-tariff/.
69 outside of normal solar production hours to better align MCE resources to match the hourly load.39 Recent market data continues to indicate that midday peak resources are likely to comprise a larger proportion of California’s renewable supply portfolio due to the rapid decline in wholesale prices for solar PV generation and the abundance of such projects in operation and under development. Additions to MCE’s portfolio during the Planning Period will likely be more heavily weighted toward energy resources – dispatchable, shaped during non-solar or ramping periods, or otherwise – that complement competitively priced solar already under contract or pair new solar projects with storage technologies to avoid exacerbating midday over-supply. MCE may also engage in purchases from as-available renewable generation (e.g., wind) to the extent that such supply is competitively priced or otherwise provides electricity during time of day when existing supply commitments are currently lacking. Additionally, MCE is working with developers of its solar projects already under contract to add storage to those existing resources to increase the number of dispatchable resources in its portfolio. In regard to project location, MCE places the greatest value on locally-sited renewable generating and storage projects, particularly those located in its service area or within approximately 100 miles thereof. In general terms, the next highest preference related to resource selection are projects sited within the California Independent System Operator’s (“CAISO”) North of Path 15 Zone (generally, Northern California), followed by projects elsewhere in California, and lastly, out-of-state resources. This procurement strategy has led MCE to achieve its desired clean energy portfolio objectives as well as cost-competitive customer rates.
39 See Agenda Item #06 from MCE’s December 2, 2021, Technical Committee Meeting, available at https://www.mcecleanenergy.org/wp-content/uploads/2021/11/MCE-Technical-Committee-Packet-December_2021.pdf. 70 Regarding new and emerging technologies, MCE has a special interest in using offshore wind, long duration battery storage and green hydrogen storage for building a carbon free portfolio for its customers and providing reliability to the grid. These technologies provide opportunities to shape MCE’s hourly portfolio to match the hourly demand. MCE has provided several letters of intent with the potential to get into long term agreements once the technology is commercially viable to developers of new and emerging technologies. MCE intends to continue this approach in the future
IV.D. Lessons Learned – Assessment of RPS Portfolio Supplies and Demand MCE’s operating history confirms that diversity among renewable energy commitments is highly desirable. This diversity encompasses a broad range of considerations, including the use of various fuel sources, resource locations, contract durations, product specifications, pricing mechanisms, solicitation timing and frequency, among other differences. Early-stage discipline in renewable energy contracting allowed for MCE’s solar energy commitments to gradually move down a declining cost curve, which avoided over-weighting the portfolio with an abundance of costly contracts. As California’s energy landscape continued to evolve, a concentration of renewable generating assets in certain locations reinforced the benefits of geographic diversity – as certain areas of the state were overbuilt with renewable generating infrastructure, challenges related to depressed market prices and related resource curtailments began to surface and will likely continue to exist for quite some time.40 There have also been challenges associated with 40 It is noteworthy, however, that economic curtailment may not be feasible for certain retail sellers when considering the financial implications of long-term contract delivery shortfalls imposed under the RPS Program. Considering such significant financial charges, certain retail sellers may be forced to accept deliveries from renewable generating assets during instances of significant negative pricing to ensure that requisite long-term contracting quantities are satisfied.

This could result in higher-than-anticipated renewable energy costs and related impacts to customer rates.
71 transmission and deliverability of projects which can impact project viability. These observations have contributed to a more rigorous evaluation process for new generating projects, e.g., analyzing congestion patterns at specific locations, understanding the risks related to obtaining Maximum Import Capability (“MIC”) for out-of-state projects and getting more involved in the CAISO regulatory processes for transmission and interconnection to understand the risks associated with transmission and deliverability for specific projects, which is expected to reduce risks associated with such issues. While historical market pricing and transmission issues are not perfect predictors of future performance, attempting to understand past trends helps to mitigate potential adverse financial consequences during near-term operation of such facilities. In addition, MCE analyzes anticipated project development in a geographic area as well as planned network upgrades in the CAISO’s Transmission Planning Process.

MCE has also adapted to how distinct California energy programs interact with one another. Assembly Bill (“AB”) 1110 (stats. 2016) has devalued and, ostensibly, discouraged the use of certain renewable energy products (allowed for use under California’s RPS Program) because of how associated emissions are accounted for under the PSD Program. Changes to PSD Program regulations related to AB 1110 attribute an emissions factor equivalent to system power to any PCC2 and PCC3 volumes. In addition, PCC3 certificates are not presented as renewable purchases during power source accounting. This change has led MCE and various other CCAs to forgo or minimize the use of PCC2 and PCC3 products to avoid representing an inflated emissions factor and the potential public/customer perception that reported renewable energy content is lower than required under California’s RPS Program or related policy commitments of the retail seller.

This adaptation to MCE’s planning and procurement practice became necessary even though such products are deemed eligible for use under California’s RPS Program. As such MCE will endeavor 72 to source all renewable energy purchases from PCC1 products but may, in isolated instances, procure small quantities of PCC2 products when unanticipated renewable energy delivery shortfalls, higher than expected retail sales and/or prevailing market conditions necessitate such purchases. Exhibiting strong preferences for PCC1 products is expected to increase costs and customer rates but will promote MCE’s achievement of emission-related portfolio objectives.

V. Project Development Status Update
As described in Section IV.B above, MCE’s current and planned procurement is sufficient to meet both the applicable RPS procurement requirements as well as support the state’s GHG reduction targets. Further, MCE’s current and planned procurement supports system reliability by considering both portfolio diversity, mid-term reliability requirements, and alignment with MCE customers’ load curve.

As of this filing, MCE has entered into three long term twelve utility-scale contracts with utility-scale RPS-eligible renewable energy resources that are not yet commercially operational, each. Eight of which is a these twelve contracts are large utility-scale project. MCE also has long term PPAs for deliveries from three smaller renewable projects, while the remaining four are smaller projects, less than 5 MWs, that were selected through MCE’s Feed-In-Tariff (“FIT”) program or DAC-GT Program – all of which are in development.. The following table 7 shows a list of the most recent projects added to MCE’s portfolio that MCE is using for RPS and/or IRP purposes to support MTR requirements, RPS, and IRP reliability and emissions goals. Each of the projects listed belowthat are either in development or have come online in the last two years to support MCE RPS and IRP-related needsyear.
73 There are also several smaller scale projects with contract capacities below 5 MWs.

MCE has updated the RNS template and the Cost Quantification templates to reflect projects listed in Table 7 below.41 MCE intends to keep the Commission informed of the progress on these projects through the various monthly and quarterly reports on project status. 41 The RNS template includes each of the resources in Table 7, with the exception of any stand-alone battery storage resources as they are not RPS eligible. However, MCE lists them in Table 7 below as they are otherwise procured as part of MCE’s larger procurement strategy. 74 Table 7: MCE Project Development StatusTable 3: MCE Project Development Status Facility Name Technology
Type
MW-ac MTR
Project
Location
(County in CA)
COD Length
of
Contract
(Years)
Network
Upgrades
Milestone
Daggett Solar Solar +
Storage
110
PV/60
Storage
Yes San Bernadino 8/25/2023 15 Completed
Golden Fields
Solar IV, LLC
Solar +
Storage
100
PV/92
Storage
Yes Kern 8/166/1/20
25 15 Completed
In progress
Strauss Wind
Project
Wind 93.3542 Yes Santa Barbara 12/20/2023 15 Completed
Humboldt
House
Geothermal 20 Yes Pershing, NV 2028
(anticipated
)6/30/2025
21 In Progress
Geysers
(7MW)
Geothermal 7 Yes Sonoma 6/1/2025 20 Completed
Key43 8-Hour
Battery
Storage
35 Yes Fresno 6/1/2027 15 Completed
In Progress
Cormorant44 Battery
Storage
188 Yes San Mateo 6/1/2026 15 CompletedIn
Progress
Corby45 Battery
Storage
100 Yes Solano 4/1/2027 15 Delayed
Allium Hybrid Solar +
Storage
110
PV/110
Storage
San Benito 5/1/2031 20 In progress
Conflitti Solar 4.4 No Fresno 3/31/2026 20 In progress
Conflitti Jr. Solar .24 No Fresno 3/31/2026 20 In progress Fallon Two
Rock Rd Solar
Farm
Solar 0.96 No Marin 1/29/20241
2/31/2023
20 Completed
Ranch Sereno Solar 2 PV/.8
Storage
No Fresno 12/31/2025
Delayed
20 In progress
75 MCE’s Large Scale Renewable Projects
There are a total of nineeight large scale new build projects with contract capacities between 7 MWs at the lower bound and a combined 110100 MW Solar/18892 MW Storage at the upper bound, which includes six RPS-eligible projects and three non-RPS-eligible projects.

The six RPS-eligible,. These projects are listed in the first eight rows in Table 3 above. In total, the eight projects are expected to produce approximately 1,463,560131,000 MWh annually. Two of RPS eligible energy. Three of the projects (, Daggett Solar,and Strauss Wind Project and Geysers), have already achieved commercial operation, while the remaining three renewable six projects are in development. MCE plans to use all nineeight of these projects to count towards its IRP-related obligation for the MTR procurement needs. mandates.

There are also several smaller scale projects with contract capacities below 5 MWs. 42MCE hasn’t yet executed a formal amendment that reduces the overall capacity of the project. 43 This is a stand-alone battery storage project that is not RPS-eligible. This resource is being provided to demonstrate additional, non-RPS MCE procurement that is in alignment with IRP needs.
44 This is a stand-alone battery storage project that is not RPS-eligible. This resource is being provided to demonstrate additional, non-RPS MCE procurement that is in alignment with IRP needs.
45 This is a stand-alone battery storage project that is not RPS-eligible. This resource is being provided to demonstrate additional, non-RPS MCE procurement that is in alignment with IRP needs.
76 MCE has updated the RNS template related to these projects and the Cost Quantification templates. Furthermore, MCE intends to keep the Commission informed of the progress on these projects through the various monthly and quarterly reports on project status.

MCE has also attached an updated version of the Project Development Status Update Report as Appendix D.

VI. Potential Compliance Delays
MCE has received favorable determinations of compliance relating to Compliance Period 1, Compliance Period 2, and Compliance Period 3, which indicate that “MCE met its RPS 46 See https://www.mcecleanenergy.org/feed-in-tariff/.
77 compliance obligations” during such periods. MCE expects similar determinations related to Compliance Period 4, which includes calendar years 2021-2024, as well as future compliance periods. This perspective is based on MCE’s past success in meeting RPS compliance mandates as well as MCE’s internally adopted, above-RPS renewable energy targets and procurement activities as well as actual renewable energy deliveries and projections,received to date (within Compliance Period 4), which seem to indicateshow (on a projected basis) that the organization is tracking well ahead of schedule in satisfying applicable RPS mandates.

Regarding long-term contracting compliance, and as discussed above, MCE has secured long-term contract commitments sufficient to meet the noted requirements throughout the planning periodthrough 2034, even in the event of potential delivery shortfalls equivalent to MCE’s adopted MMoP.

VII.A. Compliance Risk
An important element of MCE's RPS risk assessment process is determining potential vulnerabilities related to procurement and/or delivery shortfalls that could trigger deficits relative to MCE’s anticipated compliance obligations. Considering MCE’s internally adopted renewable energy procurement targets and existing contractual commitments, this risk, as internally determined by MCE, appears to be very low. As discussed throughoutelsewhere in this planplanning document, MCE has established a Voluntary Margin of Over-Procurement (“VMoP”) and, further, a MMoP that inform RPS procurement efforts and ensure against 78 compliance-related shortfalls. If there is any change in terms of MCE’s internal assessment of RPS compliance risk, MCE will inform the CPUC accordingly in a future RPS Procurement Plan.

MCE’s risk assessment and management practices are described in greater detail in Section VII, below.

In general terms, MCE’s process for minimizing and avoiding risk is deterministic in nature and begins with the development of bid requirements and evaluative preferences for solicitations. MCE’s solicitations are intended to identify suppliers that have demonstrated a strong track record of successful project completion and ongoing project operation. Such counterparties are more likely to timely complete project development activities and successfully operate projects placed under contract, and therefore minimize project risks. This process has 79 yielded strong results: the pool of responses to MCE-administered solicitation is generally robust; the quality of short-listed respondents is high and typically includes very experienced bidders with strong project development track records; the short-listed candidates, by virtue of their considerable project development and/or operational experience, tend to be efficient contract negotiators; and the resulting contracts have generally led to project deliveries that meet MCE’s expectations.

Key risk factors are considered during evaluation of each prospective renewable energy seller, including counterparty credit rating and general financial standing; California-based project development experience; prior experience with CCA off-takers; commercial viability of the proposed generating technology; and progress towards key development milestones such as interconnection status, deliverability studies, siting, zoning, permitting, and financing requirements. With regard to transmission adequacy, MCE ensures that each project has an executed interconnection agreement with the appropriate participating transmission operator prior to contract execution so that the project's interconnection costs, deliverability and timelines are known to the extent possible. MCE also conducts a review of interconnection queues and transmission planning in the area to understand impacts of planned projects and transmission upgrades. The project review process also includes a thorough review of the permitting status from the permitting authority and must demonstrate a path to completion. A selected seller bears risk of supply chain delays impacting the seller’s ability to meet its guaranteed contractual milestones on time, subject to permitted extensions and allowable Force Majeure provisions in the contract.

Additionally, MCE believes that it is important to manage temporal risks associated with:
(1) disproportionate exposure to prevailing market conditions at any particular point in time; and (2) lack of diversity related to contract start dates, end dates or term lengths within a renewable energy supply portfolio. MCE has regularly administered renewable energy solicitations throughout its operating history to ensure that its exposure to ever-changing market conditions is diversified, similar to the “dollar cost averaging” methodology that is regularly employed within the financial sector.
81 While attempts to “time the market” may occasionally yield short-lived benefits, such results are generally not reliable and create the potential for significant risk and financial consequences if market conditions quickly and/or significantly change. MCE’s deliberate contracting approach entails “sampling” the market at regular intervals, avoiding large contractual commitments in high-priced environments or missed opportunities in low-priced environments.

MCE utilizes a quantitative risk assessment that evaluates the energy impacts related to supply side losses. This approach organizes prospective risks into three general categories which pose the greatest supply-side impacts to the delivery of expected RPS energy: 1) curtailment risk; 2) resource intermittency risk; 3) counterparty risk; and 4) project cancellation risk. As part of its quantitative risk assessment, MCE examines hourly forward-looking price data and historical CAISO data to quantify curtailment risk. Considering MCE’s current long-term renewable energy positions that are well in excess of requirements, a reduction in long-term RPS volumes due to curtailment is unlikely to compromise the prospect of RPS compliance. The figures presented in the column quantifying curtailment risk in Table 84 at the end of this section are calculated by quantifying the volume of expected energy deliveries expected to occur during the balance of each contract’s respective delivery period. Thisand multiplying such volume is then multiplied by the likelihood of curtailment (expressed as a proportionate reduction in total deliveries),, which varies 82 by contract in consideration ofresource based on MCE’s historical observations related toregarding generator performance and expected performance in the future. In consideration of the increased curtailment of wind and solar resources within CAISO over the past several years36 months, MCE has assumed a minimum baseline curtailment adjustment for certain contracts within its portfolio that may be curtailed in consideration of prospective negative price risk. Based on MCE’s assessment of curtailment risk associated with its renewable energy contract portfolio, this risk category was assigned a rating of medium. When compared to the similar categorical risk assessment presented in MCE’s 2024MCE has increased the current risk rating related to curtailment, relative to its Final 2023 RPS Procurement, this risk rating remains unchanged. Plan, in consideration of the aforementioned increases in wind and solar curtailments in CAISO.

Intermittency risk has become increasingly prevalent in the wake of ongoing renewable infrastructure buildout. In particular, California’s substantial reliance on photovoltaic solar and wind generating facilities introduces intermittency risk for any retail seller procuring power from such projects. Such risks ought to be accounted for as part of a thoughtful quantitative risk assessment to ensure the identification of sufficient planning reserves. The following describes MCE’s methodology for assessing intermittency risk. As new intermittent facilities are developed to meet the procurement burdens of increasing regulatory requirements, the risk of variances between projected and actual energy deliveries is amplified. Quantifying intermittency risk is largely dependent on available data, as each generating facility is unique (geographically, operationally, etc.). As data is gathered from facilities comprising an RPS supply portfolio, planning adjustments can be incorporated to account for variances between actual and expected historical deliveries, allowing the retail seller to incorporate adjustments in its resource planning and procurement assumptions to counteract such risk. During the early stages of any delivery 83 period, however, data is often lacking so planning adjustments are more challenging to quantify and must be based on reasonable estimates derived by observing similar projects. Over time, as meaningful amounts of historical data are compiled, MCE should be able to make increasingly accurate adjustments to its planning assumptions to ensure that procured RPS volumes are more accurately aligned with anticipated needs.

Despite these challenges, MCE believes that intermittency risk can be reasonably quantified when available operating history reaches two years or more. Before substantive historical data becomes available, other information must be considered in assessing intermittency risk, including input from the asset owner/operator, insight derived from the operating history associated with similar generating facilities, and limited historical data (that can be applied to generate interim intermittency assessments). Once a generating facility has established steady-state operations, intermittency risk can be quantified by dividing the amount of actual energy received by the amount of expected energy for each year of a given contract, then averaging observed variances across each year of the available operating history. The resulting percentage is multiplied by the remaining expected energy deliveries under the contract to approximate potential delivery deficits related to intermittency. For facilities with limited operating history and/or facilities that have yet to achieve commercial operation, MCE imputes proxy intermittency adjustments to ensure conservatism in RPS planning assumptions. For example, if MCE’s experience with smaller-scale photovoltaic solar generating facilities (e.g., facilities at or below 10 MW of nameplate capacity) suggests that actual generation typically falls within negative two percent of projections, MCE will apply a negative two percent intermittency adjustment to generating facilities falling within this category. Similarly, if MCE has observed that mid-sized wind generating facilities (e.g., wind generating facilities between 20 and 100 MW of nameplate 84 capacity) occasionally produce ten percent less energy than projected in certain calendar years, it will apply a negative ten percent intermittency adjustments to generating facilities within this category. Again, this approach promotes a conservative RPS planning process and should avoid unexpected delivery shortfalls related to resource variability for intermittent generating sources.

Counterparty risk is the risk posed by a counterparty being unable or unwilling to honor its total RPS delivery obligations, as reflected in related contract documents. MCE has quantified this likelihood by considering S&P Global’s, Global Corporate Annual Default Rates by Rating Category (%) as a measure of organizational viability and financial stability. While this rate considers industries beyond the energy sector, it provides relevant insights into the correlation and potential impacts of dealing with uncreditworthy counterparties. The likelihood of default by credit rating was averaged over the years from 2014 to 2019. These years were chosen to remove irregularities in default rates during the Covid-19 pandemic; though no material impacts to MCE’s risk assessment are anticipated, MCE expects to update the time period associated with its default 85 by credit rating assessment during completion of the 2026 planning process and may shift the aforementioned time period forward to include other/additional years.. If a counterparty was found to be unrated, then the contract was reviewed to identify specified credit assurances; based on such assurances, an approximate rating was derived based on MCE’s experience and risk tolerance.

Based on MCE’s assessment of counterparty risk associated with its renewable energy contract portfolio, this risk category was assigned a rating of low. The final category reflected in MCE’s analysis is project/contract cancellation risk. This category is distinct from counterparty risk because the risk of project/contract cancellation may only affect a single project under a counterparty’s portfolio. Projects may be cancelled for a variety of reasons, but in today’s market, deals struck many months ago may no longer be economic for the seller. This risk only effects single source projects which have yet to be constructed. These projects were chosen because they have a single point of failure unlike RPS energy purchased from a pool of resources (under a portfolio-style purchase agreement in which there is generally more diversity amongst the sources of supply). Based on discussions with various counterparties, other load serving entities and its own experience, MCE has assessed that this risk affectseffects roughly 1 in 20 deals (with such circumstances generally applying to less experienced and/or reputable suppliers).. Based on MCE’s assessment of project/contract cancellation risk associated with its renewable energy contract portfolio, and the high-quality counterparties which comprise MCE’s list of suppliers, this risk category was assigned a rating of low.

Considering these categories holistically, MCE was able to derive a cumulative energy percentage at risk. In consideration of MCE’s relatively conservative risk tolerances, a top-level risk of non-delivery offset at 0.25% of renewable energy procurements was added to the calculated energy at risk percentage. This adder will help to account for risks that MCE cannot foresee and 86 will help to guarantee the sufficiency of MCE’s planned RPS purchases in meeting both compliance-related and internally adopted renewable energy procurement targets. The percentage of renewable energy and error is the percentage of total renewable energy procured that was determined to be at risk, while the percentage of retail load is the energy at risk as a percentage of retail load. These “at risk” percentages reflect possible losses which, through no fault of MCE, may occur by virtue of being a market participant. These losses pose a risk for non-compliance relative to MCE’s RPS goals and targets. Since this number is not a guaranteed loss, MCE will implement the previously mentioned mitigation strategies to give the greatest chance of meeting its adopted renewable energy procurement targets.

Table 84: MCE Contract Curtailment, Counterparty, and Project Cancellation Risk Delivery & Market Risks
ID Contract
Energy to
be Delivered
to Market
(MWh)
Curtailment
Risk (MWh)
Counterparty
Risk (MWh)
Intermittency
Risk (MWh)
Project
Cancellation
Risk (MWh)
1 Contract 333 183,851 7,354 1,839 - -
2 Contract 334 104,557 4,182 1,046 - -
4 Contract 336 263,040 10,522 2,630 - -
6 Contract 337 246,434 9,857 2,464 - -
7 Contract 342
906,989965,
261
36,280
38,610 9,070653
90,699
96,526 - -
8 Contract 343
386,291334,
581
15,452
13,383 3,863346 - - - -
9 Contract 491
3,463,88216
0,196
138,555
126,408
34,639
31,602
346,388
316,020 - -
87 10 Contract 492
24,21922,00
0 969 880 242 220 484 440 - -
11 Contract 494 5,857500 234 220 59 55 117 110 - -
12 Contract 496
3,144,9482,7
62,023
125,798
110,481
31,449
27,620
314,495
276,202 - -
13 Contract 497
21,27519,80
0 851 792 213 198 425 396 - -
14 Contract 498
21,27519,80
0 851 792 213 198 425 396 - -
15 Contract 499
2,318,29860
3,291
92,732
104,132
23,183
26,033
46,366
52,066 - -
16 Contract 500
1,317,03015
6,153
263,406
231,231
13,170
11,562
26,341
23,123 - -
17 Contract 501
426,286578,
077
85,257
115,615 4,263 5,781 8,526 11,562 - -
18 Contract 502
722,0661,44
5,193
144,413
289,039 7,221 14,452
14,441
28,904 - -
19 Contract 503
2,039,3271,4
45,193
407,865
289,039
20,393
14,452
40,787
28,904 - -
20 Contract 505
12,98014,63
0 519 585 130 146 260 293 - -
21 Contract 507
522,652722,
558
20,906
28,902 5,227 7,226
52,265
72,256 - -
88 22 Contract 586 123290,100 - - 1,231 2,901 2,462 5,802 - - 23 Contract 853
41,49528,58
1 1,660143 415 286 830 572 - -
24 Contract 855
41,49528,58
1 1,660143 415 286 830 572 - -
25 Contract 856
38,92629,09
9 1,557164 389 291 779 582 - -
26 Contract 886
38,92629,09
9 1,557164 389 291 779 582 - -
27 Contract 887
38,92629,09
9 1,557164 389 291 779 582 - -
28 Contract
1001
40,44427,88
7 1,618115 404 279 809 558 - -
29 Contract
1002
40,44427,88
7 1,618115 404 279 809 558 - -
30 Contract
1035
31,97822,40
7 1,279 896 320 224 640 448 - -
31 Contract
1068 460552 18 22 5 6 9 11 - -
32 Contract
1070
22,33218,22
0 893 729 223 182 447 364 - -
33 Contract
1071 460552 18 22 5 6 9 11 - -
89 34
Contract
1679
349,077299,
026
13,963
11,961 3,491 2,990 6,982 5,981 - -
35 Contract
1680
480,134326,
210
19,205
13,048 4,801 3,262 9,603 6,524 - -
36 Contract
1681
37,02227,18
4 1,481087 370 272 740 544 - -
37 Contract
1685
228,914187,
139
9,157
7,486 2,289 1,871 4,578 3,743 - -
38 Contract
1686
50,57642,76
1 2,023
1,710 506 428 1,012 855 - -
39 Contract
1746
427,831407,
930
17,113
16,317 4,278079
42,783
40,793 - -
40 Contract
1955
40,44427,88
7 1,618115 404 279 809 558 - -
42 Contract
2131
220,372146,
996
8,815
5,880 2,204 1,470 4,407 2,940 - -
43 Contract
2440
3,275,7542,8
48,583
131,030
113,943
32,758
28,486
65,515
56,972 - -
44 Contract
2475
47,82029,09
4 1,913164 478 291 4,782 2,909 - -
45 Contract
2522
28,59417,84
6 1,144 714 286 178 572 357 - -
90 46
Contract
3548
36,15920,79
9 1,446 832 362 208 723 416 - -
47 Contract
3549
238,194149,
349
9,528
5,974 2,382 1,493 - - - -
48 Contract
3550
19,43111,57
3 777 463 194 116 - - - -
49 Contract
3584
26,79030,26
0 1,072210 268 303 - - - -
50 Contract
3585
188,631151,
828
7,545
6,073 1,886518 3,773037 - -
51 Contract
3706
4,644,4353,0
16,624
185,777
120,665
46,444
30,166
92,889
60,332 - -
52 Contract
3710
298,982184,
191
11,959
7,368 2,990 1,842 5,980 3,684 - -
53 Contract
3720
103,11458,1
24 4,125
2,325 1,031 81 - - - -
54 Contract
3735 12,7815,774 511 231 128 58 256 115 - -
55 Contract
3736
234,535105,
925
9,381
4,237 2,345 1,059 4,691 2,119 - -
56 Contract
3749
4,335,0213,6
69,174
173,401
146,767 6,069 36,692 - - - -
91 57
Contract
3785 848,093 33,924 8,481 16,962 -
58 Contract
3864
1,121,70060
7,078
44,868
24,283 11,217 6,071 - - - -
59 Contract
3867
3,264,9631,4
88,521
130,599
59,541
32,650
14,885
65,299
29,770 - -
60 Contract
3875 45,000 - 450 900 -
61 Contract
3877
8,766,2006,6
49,800
350,648
265,992
87,662
66,498
175,324
132,996 - -
62 Contract
3878
1,227,10058
8,112
49,084
23,524 12,271 5,881
24,542
11,762 - -
64 Contract
3892 2,754,702 110,188 27,547 - -
65 Contract
3926 403,557 - 4,036 8,071 -
6963
Contract
39583891 100300,000 - - 1,000 354 - 6,000 - -
7064
Contract
39593892
100,0001,83
6,507 - 73,460 1,000 18,365 - - - -
7565
Contract
40073926
500,000681,
924 - - 590 6,819 - 13,638 - -
92 7666
Contract
40153942 100,000 - - 1,000 118 - - - -
7767
Contract
40213952
50,000185,9
64 - - 500 1,860 - - - -
7868
Contract
40223953
55,000127,7
96 - - 65 1,278 - - - -
7969
Contract
40303958 700300,000 - - 7,000 - - - - -
8070
Contract
40523959 100,000 - - 1,000 118 - - - -
8171
Contract
40563973 350140,000 - - - 1,400 - - - -
8272
Contract
40573979
450,00025,0
01 - - 531 250 - - - -
8373
Contract
40583980 200125,000 - - 2,000 - - - - -
84 Contract 4059 100,000 - 1,000 - -
85 Contract 4062 5,152,517 206,101 - 103,050 -
8674
Contract
40634003
477,749115,
645
19,110
4,626 4,777 1,156 9,555 2,313 - -
8775
Contract
40654007 200500,000 - - 2 5,000 - - - -
93 Total
Ener
gy 57,290,461 43,112,919
2,871,1063
47,624
471,734
421,969
1,587,1343
24,058 - -
Total Renewable Energy
57,290,461
Total Renewable Energy at Risk 4,929,974
% of Renewable Energy at Risk 8.61%
% of Unknown Error at Risk

0.25%
% of Renewable Energy & Error at Risk 8.86%
% of Retail Load

7.91%
Energy
Total Renewable Energy 43,112,919
Total Renewable Energy at Risk 4,093,651
% of Renewable Energy at Risk 9.50%
% of Unknown Error at Risk 0.25%
% of Renewable Energy & Error at Risk 9.75%
% of Retail Load 6.57%
Based on MCE’s updated risk assessment, MCE determined that approximately 8.69.5 percent of MCE’s expected future RPS deliveries may be at risk, which equates to 7.96.57 percent of MCE’s retail load during the current planning period (2024 through 2034) – MCE notes that the 7.96.57 percent (relative to retail load) risk statistic falls betweenis similar to MCE’s near-term MMoP of 6 percent, which applies through 2025, and thewell below its 8.5 percent MMoP, which applies in 2029 and beyond. This suggests that MCE’s MMoP is appropriately (but conservatively) set in consideration of its existing RPS supply portfolio. The noted percentages reflect average risk throughout the study period, which suggests that actual risk could fall somewhat above or below these percentages. Regardless, the potential risk-related impacts to MCE’s RPS supply portfolio align well with MCE’s MMoP trajectory, as reflected in this RPS planning process. In consideration of the results of MCE’s risk analysis, the composite risk assessment, which 94 considers all four of the previously described risk categories, results in an overall risk rating of low.

VII.C. System Reliability
With respect to system reliability, MCE is aware of the planning challenges faced by retail sellers with internally adopted renewable energy targets that exceed RPS mandates. In particular, such retail sellers must often bear increased costs for renewable resources with diverse and complementary delivery profiles, as well as comparatively high levels of energy storage infrastructure to allow for the reshaping of renewable energy deliveries to better align with load.

For example, renewable energy procurement efforts that may initially focus on relatively low-cost solar resources will often necessitate subsequent investments in co-located energy storage infrastructure and/or higher-cost baseload renewable generating technologies, such as those using geothermal, biomass and landfill gas fuel sources. These baseload renewable technologies are often priced at three-to-four times the level of in-state photovoltaic solar generation but generally provide increased capacity value due to the more predictable, baseload generating profiles of such resources, and related reliability enhancements. 95 Despite the adverse budgetary impacts, MCE continues to pursue resource acquisitions that will promote increased alignment between supply and demand as well as the increased use of locally situated renewable generating resources. Currently, low-cost, long-term solutions are incredibly challenging to identify, as ongoing increases in California’s RPS procurement mandates and technological limitations often create the need for near-term investments to balance the achievement of compliance mandates with generalized grid reliability.

Nonetheless, MCE remains committed to pursuing a conscientious planning process that balances grid reliability, compliance demonstration and customer cost impacts. Again, there are no easy solutions in addressing this dilemma, but MCE’s commitment to pursuing alignment of supply and demand as well as general resource diversity should contribute to grid reliability, reducing related risks for MCE’s customers and the system at large. In consideration of MCE’s diverse contractual commitments for requisite renewable energy supply and ongoing focus on the identification of RPS-eligible and complementary technologies that will mitigate reliability impacts associated with increased use of intermittent generating resources throughout the state, overall risks to system reliability associated with MCE’s RPS Procurement Plan were determined to be low.

VII.D. Lessons Learned – Risk Assessment
In terms of lessons learned related to risk management, MCE has observed that “more is generally better” when it comes to procuring renewable energy to satisfy RPS compliance obligations. And while this approach may not be a viable or desirable option for all retail sellers, it has served MCE well. More specifically, MCE’s 60% renewable energy commitment (which gradually increases to 85% in 20312029) has positioned the organization with substantial RPS planning reserves and minimal compliance risk. Since the 60% renewable energy commitment 96 became effective in 2017, the risks faced by MCE have transitioned away from compliance-related concerns in favor of broader integrated resource planning initiatives. MCE is now focused on identifying resources that are not only cost-effective, but complementary to its existing portfolio of renewable energy supply contracts and projected customer energy use. As the level of renewable energy increases within MCE’s portfolio, MCE has observed that the scope of resources promoting alignment between supply and demand generally becomes narrower and more costly.

In recentthe last two years, MCE has also experienced significant impacts of the MTR compliance mandate on the market for energy storage and renewable energy. The MTR compliance mandates47 require LSEs across California to bring 15,500 MW of incremental NQC capacity online in phases by 2028. The mandates further define the required characteristics for the new resources that, in some instances, restrict the new construction to specific technologies. Given the compliance mandates and market conditions such as labor shortages, increased equipment costs, and delayed deliveries of key components, buyers have seenare seeing significantly higher prices and beenbeing forced to take higher risk than normal on their long-term contracts in order to bring these resources online in time to meet the compliance requirements. As a result, developers are passing through unprecedented price increases to LSEs for new and existing contracts. While scenarios such as thisthe past two years are difficult to prepare for, one key takeaway is that timely planning and forecasting at the state level is key to building a reliable and affordable grid.

Additionally, MCE is managing these risks by working on backup plans with the developers in case there are unforeseen events, all while still being cost effective and minimizing their impact on ratepayers.
47 Please see section on MTR compliance mandate.
97 There is also concern related to the management of long-term renewable supply commitments that exist within geographic areas where negative price risk and related curtailment of energy production has become increasingly prominent. This risk is becoming more challenging to manage as California’s escalating RPS procurement mandates necessitate ongoing investment in new renewable generating infrastructure, which is often sited in resource-rich areas that become oversaturated with similar generating technologies. These circumstances seem inevitable and, over the course of a long-term supply relationship, may expose the contracted parties to unexpected risks, including negative prices (and related budgetary impacts) and curtailed deliveries which may compromise the fulfillment of mandated procurement targets by the buyer. However, MCE’s internally adopted, above-RPS renewable procurement targets allow flexibility if/when curtailment becomes necessary, or when contracted renewable resources underperform.

In terms of MCE’s contracting process, MCE has also learned that diversified sharing of risk within a renewable contract portfolio is desirable. There are many different contract structures, all of which serve a valuable purpose, which can be employed to create the desired allocation of risk between buyers and sellers. For example, an “index-plus” pricing structure is useful in transferring nodal price risk to the seller. In such structures, the buyer pays a fixed renewable premium, while the seller assumes risk associated with market price fluctuations but also receives market revenues – even though the buyer receives the energy, renewable attribute and, in certain instances, capacity value as part of such a transaction, the buyer’s financial risk is generally limited to the payment of the renewable premium. For buyers who are averse to market price risk, the index-plus pricing structure effectively eliminates this concern but may result in a higher overall contract cost, which may be acceptable as a form of insurance, to mitigate market price exposure. 98 In other structures, such as the “fixed-price” or “aggregate pricing” structure, the renewable energy premium and energy commodity (and oftentimes, capacity value) are reflected in a single price paid by the buyer – this structure deliberately allocates market price risk to the buyer, but the buyer may also pay a lower imputed renewable premium in instances where market revenues closely approximate, or exceed, the aggregate renewable energy price.

VIII. Renewable Net Short Calculations
MCE’s failure rate for new-build renewable generation placed under contract is well below five percent. MCE takes several steps to guard against the risk of project failure, including:
● Pre-contracting diligence, including a rigorous proposal evaluation process. MCE requires that any new-build project be in an advanced stage of the pre-development process, including permitting, financing, and interconnection. In particular, MCE’s practice is to 99 execute a PPA only after a project’s interconnection agreement is fully executed. This increases certainty with regard to the project’s development timeline and costs. ● Project monitoring, MCE’s PPAs for new-build projects require frequent, detailed progress reports, which helps to identify and mitigate potential problems in their early stages. ● Internal renewable portfolio targets, including a planning reserve, that meaningfully exceed statewide mandates.

MCE has increased its planned RPS procurement to account for expected delivery shortfalls and consultsquantified through its periodically updated quantitative risk assessment to determine whether further adjustments are needed to its future planning assumptions. Based on its most recently updated quantitative risk assessment, MCE determined that approximately

7.9which reflected an average 6.57 percent of future deliveries are at risk during the current planning period, shortfall/failure rate (based on projected retail load within the planning period) during the current planning period (this failure rate equates to 8.69.75 percent of projected future RPS deliveries; MCE has rounded this up to 10 percent within Appendix C). These adjustments were primarily made to address: 1) generalized planning conservatism to ensure the sufficiency of MCE’s RPS supply relative to its relatively high, internally adopted procurement targets, 2) occasional curtailment of select in-state renewable generating facilities due to negative pricing at certain times of the year; and 3) intermittency risk associated with certain renewable generating technologies, such as those using solar and wind as fuel sources. MCE continues to use actual planning data as compared to its forecast throughout the year and can adjust to supply- or demand-side variations within a given year.

MCE has provided a quantitative assessment to support the qualitative descriptions provided in this RPS Procurement Plan, which is attached as Appendix C. As previously noted, 100
MCE has successfully procured more than 60% of its resource needs from RPS-eligible renewable resources since 2017 and, as a result, has accrued renewable energy well in excess of applicable statewide mandates. With few exceptions, renewable suppliers have performed as expected, so the noted failure rates that are reflected in Exhibit C are well in excess of the findings reflected in MCE’s previously described risk assessment, which indicate that just over two percent of such supply may be at risk. If supplier performance becomes more erratic in the future and such adjustments are deemed necessary, MCE will reflect such adjustments in a future planning document.

IX. Minimum Margin of Procurement (MMoP)
IX.A MMoP Level
MCE is developing an electricity supply portfolio that will further the achievement of state mandates, as well as internally adopted goals, for increasing RPS-eligible renewable energy supply over time. The following table displays MCE’s intended margin of RPS over-procurement based on the differential between the SB 100 procurement targets and MCE’s internally adopted RPS procurement targets. This table reflects MCE’s voluntary margin of over-procurement, or VMoP.

Table 95: MCE Voluntary Margin of Over-Procurement
SB 100 RPS
Procurement
Requirement (% of
Retail Sales)
MCE’s Internally Adopted
RPS Procurement Target
(% of Retail Sales)
MCE’s Voluntary Margin
of Over-Procurement (%
of Retail Sales)
2024 44.0% 60.0% 16.0%
2025 46.7% 60.0% 131.3%
2026 49.3% 6070.0% 1020.7%
2027 52.0% 6575.0% 1323.0%
101
2028 54.7% 7080.0% 1525.3%
2029 57.3% 7585.0% 1727.7%
2030 60.0% 8085.0% 2025.0%
2031 60.0% 85.0% 25.0%
2032 60.0% 85.0% 25.0%
2033 60.0% 85.0% 25.0%
2034 60.0% 85.0% 25.0%
2035 60.0% 85.0% 25.0%
As reflected in Table 95, MCE’s RPS-eligible renewable energy target is currently set at 60 percent through 20262025, increasing to 85 percent by 20312029. MCE’s internally adopted renewable energy procurement targets are intended to support MCE’s broader goal of providing a 95 percent carbon-free electricity to all customers, beginning in 2024 and beyond, with increasing proportions of renewable energy over time. MCE’s internally adopted renewable energy procurement goals ensure a significant margin of procurement above the SB 100 mandates. Further, MCE’s internally adopted renewable energy procurement mandates provide a meaningful buffer above the state’s RPS requirements and serves as MCE’s VMoP. As shown in Table 95, MCE’s VMoP will minimally exceed statewide RPS mandates by at least 10.713.3 percent, relative to retail sales, throughout the planning periodthrough 2034.

To address RPS compliance risk, MCE uses its risk assessments, including its renewable net short calculations, to establish a Minimum Margin of Over-Procurement (MMoP) to guide RPS compliance planning. MCE calculated the MMoP by applying a 10 percent risk adjustment (or planning reserve) to the entirety of MCE’s projected Light Green renewable energy requirements. Light Green is MCE’s default retail service option, which establishes the renewable 102
energy percentage provided to all MCE customers. On a voluntary basis, MCE customers may enroll in one of MCE’s 100 percent renewable energy service offerings: Deep Green or Local Sol.48,49 Based on the way MCE has established its MMoP, the effective MMoP percentages observed by MCE throughout the planning periodthrough 2034 range from 12.29 percent in 20262025, to 14.28 percent beginning in 20312029, relative to MCE’s projected RPS compliance need. MCE’s MMoP is intended to address potential delivery variability for intermittent resources, curtailment risk, project delays or failures and other operational peculiarities that may cause actual renewable energy deliveries to deviate from projections. The table below provides additional detail regarding the effective MMoP percentages observed by MCE.

Table 106: MCE Minimum Margin of Over-Procurement
SB 100 RPS
Procurement
Requirement
(% of Retail
Sales)
MCE’s
Internally
Adopted RPS
Procurement
Target (% of
Retail Sales)
MCE’s RPS
Planning
Risk
Adjustment
(at 10% of
Internally
Adopted
RPS Target)
MCE’s
Minimum
Margin of
Over-Procurement
(% of Retail
Sales)
MCE’s
Minimum
Margin of
Over-Procurement
(% buffer
relative to
RPS
Mandate)
2024 44.0% 60.0% 10.0% 6.0% 13.6%
2025 46.7% 60.0% 10.0% 6.0% 12.9%
2026 49.3% 6070.0% 10.0% 67.0% 1214.2%
2027 52.0% 6575.0% 10.0% 67.5% 12.514.4%
2028 54.7% 7080.0% 10.0% 78.0% 12.814.6%
2029 57.3% 7585.0% 10.0% 78.5% 13.114.8%
48 See https://www.mcecleanenergy.org/100-renewable/.
49 See https://www.mcecleanenergy.org/100-local-solar/. 103
2030 60.0% 8085.0% 10.0% 8.05% 13.314.2%
2031 60.0% 85.0% 10.0% 8.5% 14.2%
2032 60.0% 85.0% 10.0% 8.5% 14.2%
2033 60.0% 85.0% 10.0% 8.5% 14.2%
2034 60.0% 85.0% 10.0% 8.5% 14.2%
2035 60.0% 85.0% 10.0% 8.5% 14.2%
IX.A.1. MMoP Methodology and Inputs
MCE’s MMoP is intended to address an RPS failure similar to that which is reflected in the RNS template. In the event of substantial under-deliveries, commercial operation delays and/or project failure, the MMoP should be sufficient to ensure MCE is compliant with the RPS procurement requirements. MCE’s VMoP is the annual RPS-eligible minimum portfolio content identified in MCE’s internally adopted planning targets.

As discussed in Section VIIVIII, MCE has incorporated risk adjustments to certain renewable energy delivery estimates associated with existing generation. Incorporated risks include: increased fire risk throughout the state of California, the potential for related delivery reductions, delivery intermittency, and resources that are under development. Achieving MCE’s MMoP requires levels of renewable energy procurement, ranging from 12.29 percent to 14.28 percent (throughout the planning period),through 2034, above MCE’s annual RPS compliance need. This additional renewable energy procurement accommodates potential delivery shortfalls due to a variety of circumstances while still allowing MCE to meet prescribed RPS mandates.

70.9%.consideration of the upcoming July 29, 2024 deadline and will advise the Commission in its Final 2024 RPS Procurement Plan if the 2023 renewable percentage noted below requires revision. MCE will continue updating this chart in future planning documents. 105
Figure 32: MCE RPS Progress Relative to Statewide Mandates IX.A.2B. MMoP and VMoP Scenarios
MCE plans to meet the annual program renewable goals reflected in the table presented in Section IX (above), including the MMoPs reflected therein. As reflected in this table, MCE’s 106
anticipated MMoP percentages range from 6.0 percent in 20252024 to 8.5 percent in 2035.20334 MCE’s RPS Procurement Targets, as well as the renewable net short reflected in the RNS Quantitative Template, incorporate the additional RPS-eligible renewable energy need resulting from expected participation in MCE’s voluntary 100 percent renewable energy service options.

During its bid evaluation and supplier selection processes, MCE considers a variety of risks and believes that such risks are sufficiently addressed within its MMoP calculation. Based on its operating history, previous experiences related to renewable energy planning/procurement and existing contract portfolio, MCE has no reason to doubt the sufficiency of the MMoP reflected in its RPS planning targets. MCE plans to procure to the VMoP since MCE’s internal RPS goals are much higher than the state mandate. This noted, MCE has incorporated an internal RPS planning reserve, as reflected in the following table, to ensure MCE can meet its internal RPS targets in the event that its previously described contract management process identifies substantial concerns related to new-build project completion, delivery shortfalls or other issues.

This reserve is additive to MCE’s internally adopted RPS targets and is intended to address renewable production and/or usage variability that may occur during discrete calendar years. It is intended to offset the potential impacts of noted risk adjustments and /contingencies that may reduce actual renewable energy deliveries, relative to MCE’s expectations. In effect, MCE’s internal RPS planning reserve is a secondary VMoP, providing additional insurance against unforeseen circumstances that could impact MCE’s ability to satisfy its internally adopted renewable energy commitments. As demand- and supply-side data are monitored in each year, MCE may adjust planned short-term purchases and/or pursue surplus sales arrangements if actual renewable energy deliveries are tracking above MCE’s anticipated needs. By the end of each calendar year, MCE hopes to manage the level of its internal planning reserve so that actual 107
renewable energy deliveries are closely aligned with MCE’s Base RPS Procurement Target, as reflected below.

Table 128: MCE RPS Procurement Target
SB 100 RPS
Procurement
Requirement
(% of Retail
Sales)
MCE’s
Internally
Adopted RPS
Procurement
Target (% of
Retail Sales)
MCE’s
Voluntary
Margin of Over-Procurement
(% of Retail
Sales)
MCE’s
Minimum
Margin of Over-Procurement
(% of Retail
Sales)
MCE’s
Aggregate
Margin of Over-Procurement
(% of Retail
Sales)
2024 44.0% 60.0% 16.0% 6.0% 22.0%
2025 46.7% 606.0% 13.3% 6.0% 19.3%
2026 49.3% 6070.0% 1020.7% 67.0% 1627.7%
2027 52.0% 6575.0% 1323.0% 67.5% 1930.5%
2028 54.7% 7080.0% 1525.3% 78.0% 2233.3%
2029 57.3% 7585.0% 1727.7% 78.5% 2536.2%
2030 60.0% 8085.0% 2025.0% 8.05% 28.033.5%
2031 60.0% 85.0% 25.0% 8.5% 33.5%
2032 60.0% 85.0% 25.0% 8.5% 33.5%
2033 60.0% 85.0% 25.0% 8.5% 33.5%
2034 60.0% 85.0% 25.0% 8.5% 33.5%
2035 60.0% 85.0% 25.0% 8.5% 33.5%
MCE will also model demand-side sensitivities that may impact MMoP and VMoP calculations. This will be particularly important during periods of expansion of MCE’s service area, when participation rates are expected to be most volatile. While MCE has no current expansion plans, MCE has completed numerous expansions during its 13-year operating history, 108
and in each case, MCE has successfully scaled its renewable energy procurement to accommodate related increases in retail sales. In addition to load variability resulting from periodic expansions and ongoing minor fluctuations in customer participation, MCE will also monitor large load growth (for example Data Center load growth), electric vehicle penetration rates, net energy metering participation rates and other considerations that may impact overall customer energy requirements and related procurement margin calculations.

X. Bid Solicitation Protocol
X.A. Solicitation Protocols for Renewables Sales
MCE does not have immediate plans to issue a solicitation for sales of renewable energy projects.

X.B. Bid Selection Protocols
(i) Description of Bid Solicitation Protocols.

1. Overall quality of response, inclusive of completeness, timeliness, and conformity;

2. Price and relative value within MCE’s supply portfolio;

3. Project location and local benefits, including local hiring, and prevailing wage considerations and community benefits packages;

4. Project development status, including but not limited to progress toward interconnection, deliverability, siting, zoning, permitting, and financing requirements; 109

5. Qualifications, experience, financial stability, and structure of the prospective project team (including its ownership);

6. Environmental impacts and related mitigation requirements, including impacts to air pollution within communities that have been disproportionately impacted by the existing generating fleet;

7. Potential impacts to grid reliability;

8. Potential economic benefits created within communities with high levels of poverty and unemployment;

9. Acceptance of MCE’s standard contract terms; and

10. Development milestone schedule, if applicable.

Consistent with Public Utilities Code Section 399.13(a)(6)(C), MCE conducts energy product solicitations in a manner that addresses a broad range of considerations, including specific needs for eligible renewable energy resources (reflecting locational preferences, when applicable, 110
for such resources), generating capacity, and required online dates to assist in determining what resources fit best within its desired supply portfolio. Since MCE’s governing board is comprised of local elected officials, solicitation and procurement decisions are overseen by elected representatives of MCE’s member communities with such decisions intended to conform with locally established targets that exceed applicable RPS requirements and promote the development of locally-situated renewable generating facilities.
(ii) Consideration of Resources Located in Disadvantaged Communities.

Information regarding other MCE service offerings and programs, including its FIT, can be found 111
elsewhere on the MCE website.50
X.B. Solicitation Protocols for Renewables Sales
MCE does not have immediate plans to issue a solicitation for sales of renewable energy projects.

X.C. LCBF Criteria
The Least-Cost Best Fit (“LCBF”) methodologies approved by the Commission pursuant to D.04-07-029, D.11-04-030, D.12-11-016, D.14-11-042, and D.16-12-044 are expressly only directly applicable to investor-owned utilities. However, consistent with Section 399.13(a)(9),51 MCE does consider best-fit attributes that support a balanced mix of resources to help support grid reliability.

The term “fit”“Fit” also has as much to do with organizational compatibility between buyers and sellers and alignment with key organizational objectives as it does with balancing customer usage and expected project deliveries, particularly when considering long-term contracting opportunities that will require constructive working relationships over a period of ten years or more. In the most recent Open Season solicitations, MCE also added a focus on matching the supply to the hourly load shapes and evaluatewill be evaluating projects based on the overall fit of the portfolio. As such, MCE’s LCBF methodology takes into consideration the various planning and procurement processes described in this RPS Procurement Plan, balancing a variety of pertinent considerations at the time that each renewable purchase opportunity is being considered.

MCE’s Power Purchase Agreement includesinclude safety terms such as Prudent Operating Practice and Maintenance of Health and Safety provisions, which speak to safety precautions with respect to the operation, maintenance, repair, and replacement of a project.

This Section describes how MCE has taken actions to reduce the safety risks posed by its renewable resource portfolio and how MCE supports the state’s environmental, safety, and energy policy goals.
52 Cal. Pub. Util. Code § 399.13(a)(8)(1) (“In soliciting and procuring eligible renewable energy resources for California-based projects, each electrical corporation shall give preference to renewable energy projects that provide environmental and economic benefits to communities afflicted with poverty or high unemployment, or that suffer from high emission levels of toxic air contaminants, criteria air pollutants, and greenhouse gases.”). 114
XI.A. Wildfire Risks and Vegetation Management
At this point in time, MCE has yet to adopt any additional safety requirements for its portfolio that are specific to wildfire risks and vegetation management. MCE is aware of the mitigating impacts that biomass generators, which use forestry waste as feedstock, may have on wildfire risk, and has adopted principles on responsible but does not have any specific procurement policies or preferences for forest biomass electricity development which state that MCE will prioritize resources that support sustainable forest management and wildlife reduction strategies to minimize the fuels for uncontrolled wildfire.53at this time. As mentioned in Section III, MCE has engaged with the CPUC on laying the policy foundation for CCA participation in the BioMAT program, which is inclusive of woody biomass facilities that use feedstock from fuel reduction facilities or sustainable forest management, including from such feedstocks from high hazard zones.54
XI.B. Decommissioning Facilities
MCE does not own any generating assets, and as such does not undertake decommissioning of assets. MCE has not yet developed any plans or requirements related to the disposition of associated generating facilities following completion of applicable delivery terms. In many cases, the project’s operational life is longer than MCE’s contract, so it is likely that the contract with MCE will expire before disposal of the generation assets is required. 53 See https://www.mcecleanenergy.org/wp-content/uploads/2021/11/MCE-Technical-Committee-Packet-Thursday-November-4-2021.pdf at 106. 54 PG&E’s BioMAT Market Adjusting Tariff, Section 14.c, Sheet 22:
https://www.pge.com/assets/pge/docs/about/doing-business-with-pge/ELEC_SCHEDS_E-BioMAT.pdfhttps://www.pge.com/assets/pge/docs/about/doing-business-with-pge/ELEC_SCHEDS_E-BioMAT.pdf 115
In 2015, SB 489 authorized the California Department of Toxic Substances Control (“DTSC”) to add PV panels to the list of universal wastes. The DTSC has developed regulations for PV panels, but has not adopted the regulations yet.55 Because a significant portion of MCE’s solar facilities are newly constructed, and its storage facilities are yet to be constructed, MCE is confident that by the time PV solar or battery facilities under contract with MCE reach the end of their useful life, there will be statewide, comprehensive regulations addressing the safe handling and disposal/recycling of those materials.

XI.C. Climate Change Adaptation
MCE’s commitment to increasing renewable energy at a more aggressive pace than California’s statewide mandates itself constitutes a climate change adaptation measure.

Additionally, MCE in 2019 adopted a pollinator-friendly habitat requirement for solar projects participating in both its FIT program as well as its PPAs.56 MCE is the first California CCA to adopt this requirement, demonstratingwhich is a critical function thatway MCE, as a CCA, can take to help build and maintain healthy ecosystems in the local areas where MCE’s solar projects are located. MCE will continue to evaluate the potential impacts of climate change on its portfolio so that adjustments to its procurement strategy can be made asif needed.

XI.D. Impacts During Public Safety Power Shut-off Events Public Safety Power Shut-off (“PSPS”) events have both supply and demand side impacts.

The experiences of MCE customers with wildfires and PSPS events over the last few years has led MCE to increase the focus of both its procurement as well as customer programs strategies on 55 See https://dtsc.ca.gov/photovoltaic-modules-pv-modules-universal-waste-management-regulations/. 56 See https://mcecleanenergy.org/pollinator-friendly-ground-cover-now-required-for-new-solar-projects/. 116
resiliency.

MCE assesses customer usage as a result of a PSPS event, to the extent possible with the data to which MCE has access, in real time and adjustments to supply are made accordingly.

XI.E. Forest Biomass Procurement
In recent renewable Open Season requests for offers, MCE has not received offers from forest biomass generators. MCE’s FIT program is available on a first-come, first-served basis, and is also technology-agnostic, however, MCE has not received any forest biomass applications.

XII. Consideration of Price Adjustment Mechanisms
AtIn the time of this filingfuture, and consistent with SB 350 and SB 100, MCE will review the possibility of incorporating price adjustments in contracts with online dates more than 57 R.24-05-02318-12-005 and R.19-09-009, respectively.
117
24 months after the date of contract execution. As noted in the ACR, such price adjustments could include price indexing to key components or to the Consumer Price Index.

XIII. Curtailment Frequency, Cost, and Forecasting
This Section responds to the questions presented in Section 6.13 of the ACR58 and describes MCE’s strategies and experience so far in managing the Agency’s exposure to negative pricing events, overgeneration, and economic curtailment for MCE’s region and portfolio of renewable resources.

XIII.A. Factors Having the Most Impact on the Projected Increases in Incidences of Overgeneration and Negative Market Price Hours
Due in large part to the rapid increase in the amount of wind and solar generation that has not been coming online throughout the western United States, the California Independent System Operator’s (“CAISO”) Balancing Authority Area (BAA) has experienced an increasing frequency and magnitude of curtailment and negative pricing events. The U.S. Energy Information Agency (“EIA”) estimates that as of March 2024, California has 37,507.1 MW of total installed solar capacity, with 17,191.5 MW of that total being behind-the meter solar.59 The CAISO reports that it has approximately 19,479 MW of utility-scale solar and 8,120 MW of utility-scale wind currently installed within its BAA.60 This capacity results in discrete periods where the majority of load in the CAISO is served by solar and wind resources. The monthly maximum load served by wind and solar in the CAISO has averaged 71.5% over the past 5 years (April 2019 to April 58 ACR at 31-32.
59 EIA, Electric Power Monthly, Table 6.2.B. Net Summer Capacity Using Primarily Renewable Energy Sources and by State, April 2024 and 2023 (Megawatts), available at:
https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=table_6_02_b. 60 CAISO, What are we doing to green the grid?, updated April, 2024, at https://www.caiso.com/about/our-business/managing-the-evolving-grid 118
2024), and the monthly maximum load served by wind and solar exceeded 109%.61 To address the resulting instances of over-supply, the amount of curtailment of wind and solar in the CAISO has significantly increased each year from 2015 through 2022, totaling 187,000 MWh in 2015, 308,000 MWh in 2016, 358,000 MWh in 2017, 461,000 MWh in 2018, 961,000 MWh in 2019, 1,587,497 MWh in 2020, 1,504,803 in 2021, and 2,449,248 in 2022 and 2,659,526 MWh in 2023. As of May 31, 2024, the total curtailment of solar and wind year to date is 1,899,759 MWh. Curtailment is typically the highest during the months of March, April, and May when hydroelectric generation is historically at its highest and California load is at its lowest. Years in which there is an above-average snowpack results in higher-than-average hydroelectric generation which exacerbates renewable generation curtailment. The table below summarizes solar and wind curtailment from January 2024 through April 2024.
61 CAISO, Monthly Renewables Performance Report, February 2024, available at https://www.caiso.com/documents/monthlyrenewablesperformancereport-feb2024.html 119
Table 9: Summary of CAISO Solar and Wind Curtailment January-April 2024 2024 Data Wind Curtailment
(MWh)
Solar Curtailment
(MWh)
January 5,515 95,505
February 15,263 213,625
March 54,677 675,569
April 41,781 797,804
Total Curtailment 117,236 1,782,523
Curtailment % 1.65 % 13.75%
No. of Intervals Curtailed 9218 13351
Pct. of Intervals Curtailed 26.45 38.31
The CAISO notes that the majority of renewable resource curtailment is “a result of economic downward dispatch, rather than self-schedule curtailment,” and that “Most renewable generation dispatched down in the ISO were solar resources, rather than wind, because solar resources typically bid more economic downward capacity than wind resources.62 That means that curtailment happened in response to congestion and was mitigated by supply that was willing to reduce its output based on price signals from the CAISO market.

CAISO system-wide 2024 curtailment percentages are higher than forecasted by MCE to date. Thus far in 2024 through May, MCE has experienced 82,501 MWh of curtailment, which is over 8% of MCE’s RPS portfolio. Curtailment to MCE’s RPS portfolio is predominantly composed of the Little Bear Solar resources, which is 90% of MCE’s curtailment volume. MCE has been in discussions with the CAISO regarding local network upgrades required and potential 62 CAISO, 2020 Annual Report on Market Issues and Performance Report, published January 20, 2022, page 41, available at http://www.caiso.com/Documents/2020-Annual-Report-on-Market-Issues-and-Performance.pdf. 120
for adding a battery to the project to alleviate Little Bear Solar curtailment.

XIII.B. Written Description of Quantitative Analysis of Forecast of the Number of Hours Per Year of Negative Market Pricing for the Next 10 Years MCE’s scheduling coordinator agent, ZGlobal, has the capability to perform production cost analyses based on various input assumptions through 2035 to derive hourly market prices for energy and ancillary services. PLEXOS Integrated Energy Model is a commercial optimization engine that can simulate the economic commitment and dispatch used by the CAISO’s day-ahead market processes which simultaneously optimizes energy dispatch and ancillary services capacity awards across the CAISO grid. In this way, the simulation will determine locational marginal prices and ancillary service marginal prices in the same manner the CAISO day-ahead market sets prices. ZGlobal has developed models using input assumptions that are based on common case inputs and planning guidelines from WECC, CAISO, Commission and CEC.

The key assumptions considered for the assessment included the impact of higher California renewable energy standards (60% RPS by 2030), planned gas-fired and nuclear generation retirements and adopted any specific price adjustment mechanisms.California Energy Commission (“CEC”) demand forecasts which consider energy efficiency programs and increased behind-the-meter solar generation. Results are highly dependent upon input assumptions, primarily the level of new RPS generation, deployment of energy storage facilities, upgrades to CAISO-controlled transmission facilities and the ability to export energy from the CAISO to external balancing areas.63
63 More recently, load has become an important input variable with the onset of the COVID-19 pandemic and its effect on load. However, ZGlobal has not performed long-term studies to determine the impact of load on long-term market prices as there is not enough data to determine a suitable load trajectory.
121
In California, electricity prices are typically set by gas-fired resources operating on the margin. However, in light of the current political landscape and ongoing affordability concerns for LSEs and as increasing supplies of renewable energy are added to the system, there are periods where marginal prices are being set by zero or even negatively-priced resources. Market prices have been trending downward, especially during seasons and periods of the day when loads are low and solar output is high with the influx of renewable energy resources. The modeling shows that during solar hours, prices are low during the middle of the day, driven by solar resources and their willingness to curtail and increasing in the morning and evening when gas-fired resources are needed to meet peak loads outside of the solar supply period. In short, prices as reflected by the CAISO’s duck curve are expected to continue, with the amplitude of the valley and ramps dictated by the amount of energy storage available to smooth out the net supply.

XIII.C. Experience, to Date, With Managing Exposure to Negative Market Prices and/or Lessons Learned from Other Retail Sellers in California MCE closely monitors six separate locations that are indicative of renewable energy resources that are exposed to market prices and potential curtailment. Resources at those locations are bid into the CAISO markets and are curtailed when prices fall below individual resource’s threshold prices. Weighted average prices for the generation at those locations are compared to weighted average prices at PG&E’s Distributed Load Aggregation Point (“DLAP”) to assess the impact of congestion on the resource’s performance. In addition, the MWh of curtailment are logged.

If curtailment is caused by congestion, the impact can be somewhat mitigated by obtaining CAISO Congestion Revenue Rights (“CRRs”), which MCE has done. However, CRRs are not a perfect hedge against congestion and cannot be relied upon to mitigate congestion and subsequent economic curtailment entirely.

XIII.D. Direct Costs Incurred, to Date, for Incidences of Overgeneration and Associated Negative Market Prices
For calendar year 2024 through May, MCE’s RPS portfolio has been exposed to negative market prices and experienced curtailment as summarized in the table below.

Table 10: Summary of MCE RPS Resources Curtailment January-May 2024 Location Day-Ahead
Negative Prices
Real-Time
Negative Prices
Curtailment
(MWh)
Cost of
Curtailment ($)
South P26 -$20.68 -$28.51 4,312 $254,071
Fresno 1 -$66.40 -$82.34 74,089 $7,356,470
Fresno 2 -$25.06 -$32.20 1,843 $90,300
North P26 -$33.32 -$41.35 2,257 $149,982
Total -$95.16 82,501 $7,850,823
The Day-Ahead and Real-Time Negative Price columns represent averages of negative 123
prices by RPS geographic area when prices are negative for solar hours for solar resources and all hours for wind resources. The prices are averages based on resources within the area. Curtailment megawatt hour (“MWh”) is the amount of energy that MCE RPS resources in the areas were curtailed from January 1 through May 31, 2024. “Cost of Curtailment” is the subsequent market cost of the curtailed energy.

XIII.E. An Overall Strategy for Managing the Overall Cost Impact of Increasing Incidences of Overgeneration and Negative Market Prices While curtailment is a viable renewable integration strategy that is generally more cost-effective than other options, there are potential negative consequences from excessive curtailment.

Curtailment of solar and wind represents a lost opportunity to generate zero-GHG electricity, and excessive curtailment could impact the ability of the state to meet its environmental and energy policy goals. Additionally, these over-supply situations expose ratepayers throughout California,to increased costs because their load serving entities must either economically curtail the generating resource (and often pay for the electricity that was not generated) or generate power and be exposed to negative prices.

MCE will consider the impact of curtailment and negative pricing on its portfolio and will factor potential curtailment into its long-term planning. Due to the difficulty in accurately forecasting curtailment, MCE will review the historical data on curtailment and negative pricing within regions where MCE may consider incorporating price adjustment mechanisms to protect ratepayers from market uncertaintycontract for generating resources. When MCE is evaluating new procurement opportunities, the potential amount of future curtailment will be one factor that MCE will consider. While MCE has not yet developed an individualized forecast of future curtailment, MCE will factor potential curtailment into its minimum margin of procurement 124
(described in Section IX) and may also factor this consideration in future iterations of its Risk Assessment (Section VII). To the extent that MCE is engaged in renewable supply agreements which include curtailment provisions, it will take actions to limit the impacts of curtailment on its customers. During its current and future renewable contracting efforts, MCE will pursue contract terms that recognize and limit the potential financial impacts of negative pricing and give MCE greater flexibility to direct economic curtailment, if this becomes necessary.

XIII.F. Contract Terms Included in RPS Contracts Intended to Reduce the Likelihood of Curtailment or Protect Against Negative Prices.

MCE has negotiated pre-paid curtailment hours into some of its new contracts and has a strong preference to be the scheduling coordinator so that it can modify the bidding strategies to mitigate impacts of curtailment.

XIIIXIV. Cost Quantification
MCE has provided the Cost Quantification Table as Appendix E. Pursuant to the direction in the ACR, MCE has completed those cells in the Cost Quantification table that correspond to Table 32, Rows 1-5 in the ACR.

XV. Conformance with the IRP Proceeding
The resources identified in this RPS Procurement Plan are consistent with the resources identified in MCE’s 2022 IRP, which was submitted to the Commission for certification on November 1, 2022, and with biannual MTR updates provided to the Commission regarding MCE’s progress towards meeting procurement requirements under D.21-06-035 and D.23-02-040.64 As required by the ACR,65 MCE includes the Table 11 below, which describes how MCE’s 2024 RPS 64 Since filing its 2022 Compliance IRP, MCE has filed four biannual MTR update filings on February 1, 2023, August 1, 2023, December 1, 2023, and June 3, 2024, respectively. 65 ACR at 32-35.
125
Procurement Plan conforms with the determinations made in the IRP Proceedings (R.16-02-007 and R.20-05-003). As required, MCE highlights the interrelationships of its RPS and IRP planning processes in this RPS Procurement Plan. The following table reflects MCE’s current updates, as reflected in this RPS Procurement Plan, regarding RPS alignment with the 2022 IRP process.

Table 11: RPS Alignment in MCE’s IRP
IRP Section
Subsection
RPS Alignment in IRP
III. Study Results
A. Conforming and
Alternative
Portfolios
Retail sellers should explain how the RPS resources they plan to procure, outlined in their RPS Plan, will align with each of their Conforming Portfolios being developed in their IRP Plans for Commission approval and certification. This explanation should include:

1. Existing RPS resources
that the retail seller owns
or contracts.

2. Existing RPS resources
that the retail seller plans
to contract with in the
future.

3. New RPS resources that
the retail seller plans to
invest in.

4. New and existing
resources that will be used
to meet Mid-Term
Reliability obligations
adopted in D.21-06-035
and the supplemental
procurement ordered in
D.23-02-040.

The Commission certified MCE’s 2022
Compliance IRP per Ordering Paragraph 5
of D.24-02-047. Pursuant to D.24-02-047
and the Assigned Commissioner’s
Amended Scoping Memo and Ruling
Extending Statutory Deadline, issued
April 18, 2024, MCE’s next full update to
its 2022 Compliance IRP will not be filed
until November 1, 2025. As part of this
last biennial IRP filing MCE submitted a
single Preferred Conforming Portfolio
(PCP) that meets MCE’s internal and
mandated RPS targets and achieves
MCE’s proportional share of both the 30
MMT GHG targets (i.e. 38 MMT by 2030
and 30 MMT by 2035) and the 25 MMT
GHG targets (i.e. 30 MMT by 2030 and
25 MMT by 2035). MCE provided the
same PCP for consideration under both
aforementioned GHG target scenarios. For
its PCP, new resources were added to
MCE’s currently contracted RPS
resources to achieve the respective GHG
targets as well as RPS procurement
126
requirements, including the 65% long-term contracting requirement.

Description of MCE’s PCP:
● MCE’s PCP achieves an overall
portfolio GHG target below MCE’s
assigned share of the 2030 and 2035
emissions under both the 30 MMT and
25 MMT scenarios.
● Using the CPUC’s embedded
assumptions in the 30 MMT portfolio,
MCE’s emissions registered at 0.500
MMT relative to MCE’s assigned
share of 0.848 MMT in 2030 and

0.514 MMT relative to MCE’s
assigned share of 0.630 MMT in 2035.
● Using the CPUC’s embedded
assumptions in the 25 MMT portfolio,
MCE’s emissions registered at 0.493
MMT relative to MCE’s assigned
share of 0.640 MMT in 2030 and

0.492 MMT relative to 0.504 MMT in
2035.
● MCE’s PCP assumed the use of RPS
resources that were reflected in
MCE’s supply portfolio at the time of
the 2022 Compliance IRP filing.
● The planned RPS-eligible resources
reflected in MCE’s PCP included: 109
MW geothermal; 356 MW wind
(consisting of in-state, out-of-state,
and off-shore); and 222 MW solar
o Of the aforementioned PCP
resources, MCE anticipated the
following new RPS-eligible
capacity additions: new hybrid
resources totaling 212 MW solar/
153 MW battery storage, 109
MW of geothermal, and new wind
resources totaling 265 MW
● Pursuant to D.21-06-035, MCE was
assigned 332 MW of incremental Net
Qualifying Capacity to meet its share
127
of state’s MTR need. MCE was also
assigned an additional 122 MW of
incremental Net Qualifying Capacity
to be online by 2027 pursuant to D.23-
02-040. As reflected in MCE’s 2022
PCP, MCE is actively procuring to
meet the initial MTR need and the
supplemental need on the mandated
timelines. To date, MCE has executed
a number of contracts for RPS-eligible
resources that contribute towards
MCE’s RPS needs and MTR
requirements. Due to circumstances
outside of MCE’s control, however,
some contracted RPS and mid-term
reliability resources have fallen out of
MCE’s portfolio or are delayed, or
expected to be delayed, beyond the
initial milestone and commercial
operation dates. Moreover, regulatory
and market conditions coupled with
insufficient transmission capacity and
deliverability allocations has limited
MCE’s ability to procure resources
that meet both the attributes and
timelines mandated by the
Commission. At the time of this filing,
MCE’s existing executed MTR
agreements include the following
incremental capacity amounts: 27 MW
of nameplate geothermal capacity ;
100 MW nameplate solar paired with
92 MW of nameplate storage; and 110
MW of nameplate solar paired with 60
MW of nameplate storage, and 93.35
MW of nameplate wind capacity.
● Although not RPS-eligible, MCE has
also executed several agreements for
stand-alone storage that will be
applied towards MCE’s generic MTR
needs. These non-RPS-eligible
contracts amount to 323 MW of
nameplate storage capacity.
● MCE is pursuing additional
procurement to satisfy MTR open
128
positions, including the supplemental
procurement under D.23-02-040, via
its 2024 Open Season, some of which
procurement will also be eligible to
contribute towards MCE’s RPS needs.

IV. Action Plan
A. Proposed
Activities
Retail sellers should describe how they propose to use RPS resources to implement both Conforming Portfolios. Narratives should include:

1. Proposed RPS
procurement activities as
required by Commission
decision or mandated
procurement.

2. Procurement plans,
potential barriers, and
resource viability for each
new RPS resource
identified.

MCE’s compliance with the IRP
incremental procurement obligation
required by D.19-11-016 has been met
through a mix of resources currently under
contract and online, some of which are
RPS-eligible. Such incremental capacity is
comprised of the following resource types:
natural gas (Sutter Energy Center), solar,
landfill-gas-to-energy generation, and
demand response. These resources are
further described in MCE’s 2022 IRP and
MCE’s biannual MTR update filings filed
in February 2023 and August 2023. .

As part of its Open Season procurement
process and additional efforts to secure
resources to meet MTR procurement
requirements under D.21-06-035 and
D.23-02-040, as described above, MCE
also contracted for two hybrid resources,
which are expected to provide additional
RPS-eligible incremental capacity. MCE’s
prior RPS procurement plan indicated
MCE had four geothermal projects under
contract (three of which were new,
incremental geothermal capacity). As of
this filing, due to contract failure of one of
those geothermal projects, MCE has three
geothermal projects under contract (2 of
129
which are incremental geothermal
capacity) All of the aforementioned
projects are under long-term contract.

For detailed descriptions of MCE’s MTR
procurement, please refer to MCE’s MTR
update filings that were filed with the
Commission in February 2023, August
2023, December 2023, and June 2024.

MCE is currently administering 2024
Open Season procurement processes to fill
outstanding resource needs required to
meet portfolio specifications reflected in
its PCP, MTR requirements, as well as
any other internal and state-mandated RPS
or reliability procurement targets. To the
extent additional resources are needed,
MCE is conducting supplemental, smaller
solicitations and pursuing bilateral
negotiations.

1. The type of solicitation.

2. The timeline for each
solicitation.

3. Desired online dates.

4. Other relevant
procurement planning
information, such as
solicitation goals and
objectives.

MCE will issue future solicitations, as
described above in Section X, on a
timeline that is appropriate for the
resource development plan reflected in its
PCP, consistent with MTR procurement
timelines and attributes, and that will
allow MCE to meet its internal as well as
state-mandated RPS targets. MCE
typically administers its annual Open
Season procurement processes each
Spring and, as part of such processes, may
pursue additional resources that will be
needed to fulfill resource specifications
reflected in its PCP or to meet MTR
requirements. MCE’s 2024 Open Season
specifically targeted PCC 1-eligible
renewable energy generating facilities that
may be paired with energy storage. MCE
expects this Open Season process to
conclude Q3/early Q4 2024.
130
In addition to the Open Season
solicitations, MCE also solicits offers for
short term PCC1 renewable energy
purchases/sales for annual portfolio
balancing. Additionally, MCE also
participates in the PG&E VAMO process
and receives an allocation of renewable
energy from the PG&E’s PCIA portfolio.

1. Key market, regulatory,
financial, or other
resource viability barriers
or risks associated with
the RPS resources coming
online in both retail
sellers’ Preferred
Portfolios.

2. Key risks associated
with the potential
retirement of existing RPS
resources on which the
retail seller intends to rely
in the future.

MCE notes that even though a balanced,
diverse RPS portfolio is desirable, the
limited resource availability and lead time
required for some technology types may
necessitate planning flexibility. While
MCE has a highly successful track record
of contracting with new-build renewable
resources, there is always a risk of project
failure due to market and regulatory
conditions beyond MCE’s control. Of
increasing concern to MCE is the growing
interconnection queue and delays in
processing the unprecedented numbers of
applications for interconnection studies
and deliverability. Restrictions and
uncertainty on this front increase risk and
uncertainty for LSEs and can ultimately
present a material barrier to LSEs bringing
on new RPS resources that have sufficient
deliverability to meet RPS program and
reliability needs. Adding to this constraint
are lingering supply chain issues and
permitting delays that impact timely
development and interconnection of new
resources.
131
XIVXVI. Impact of Transmission and Interconnection Delays SB 1174 (stats. 2022, ch. 229) requires electrical corporations that own transmission lines to report to the Commission on the development of transmission and interconnection facilities necessary to provide transmission deliverability for renewable energy and/or energy storage facilities that have executed interconnection agreements. MCE is not subject to the requirements of SB 1174 and does not own any transmission lines. Accordingly, MCE has not included a Transmission/Interconnection Delay Data Report as an attachment to this RPS Procurement Plan.

Dated: June 30, 2025July 23, 2024 Respectfully submitted, /s/Sai PowarAmulya Yerrapotu
Sai PowarAmulya Yerrapotu
Policy Analyst
Marin Clean Energy
1125 Tamalpais Avenue
San Rafael, CA 94901
(415) 464-60446670
[email protected]
Appendix B
Draft 2025 RPS Procurement Plan Checklist and Verification Draft 2025 RPS Procurement Plan Checklist- Task Completed Retail seller name: Marin Clean Energy YES/NO NOTES
I. Summary of Major Changes to RPS Plan YES
II. Executive Summary Key Issues YES
III. Compliance with Recent Legislation and Impact of
Regulatory YES
IV. Assessment of RPS Portfolio Supplies and Demand YES IV.A. Portfolio Supply and Demand YES
IV.A.1. Long-term Procurement YES
IV.B. Portfolio Diversity and Reliability YES
IV.B.1 Forecasting for Increased Transportation
Electrification YES
IV.B.2 Curtailment Frequency, Cost, and Forecasting YES IV.C. Portfolio Optimization YES
IV.C.1 Conformance with the IRP Proceeding YES
IV.C.2 Response to Local and Regional Policies YES
IV.D. Lessons Learned YES
V. Project Development Status Update YES
VI. Potential Compliance Delays YES
VII. Risk Assessment YES
VII.A Compliance Risk YES
VII.B Risk Modeling and Risk Factors YES
VII.C Lessons Learned YES
VIII. Renewable Net Short Calculation YES
IX. Minimum Margin of Procurement (MMoP) YES
IX.A MMoP Level YES
IX.A.1 MMoP Methodology and Inputs YES
IX.A.2 MMoP Scenarios YES
X. Bid Solicitation Protocol YES
X.A. Bid Selection Protocols YES
X.B. Solicitation Protocols for Renewables Sales YES
X.C. Least-Cost Best-Fit (LCBF) Criteria YES
XI. Safety Considerations YES
XII. Consideration of Price Adjustments Mechanisms YES
XIII. Cost Quantification YES
XIV. Impact of Transmission and Interconnection Delays N/A Appendix A: Redlined Version of the Draft 2025 RPS Plan YES Officer Verification
I am an officer of the reporting organization herein and am authorized to make this verification on its behalf. The statements in the foregoing document are true of my own knowledge, except as to matters which are therein stated on information or belief, and as to those matters, I believe them to be true. The spreadsheet templates used within this filing have not been altered from the version issued or approved by Energy Division.

Executed on June 30, 2025 at San Rafael, California.
/s/ Vicken Kasarjian
Vicken Kasarjian
Chief Operating Officer
Marin Clean Energy
1125 Tamalpais Avenue
San Rafael, CA 94901
(415) 464-6659
[email protected]
Appendix C
Renewable Net Short Calculation
LSE Name: Input required No input required
Date Filed: 6/30/25
Variable Calculation Item 2021 Actual 2022 Actual 2023 Actual 2024 Actual 2021-2024 Forecast Year CP 4
Annual RPS Requirement
A Total Retail Sales (MWh)
5,333,206 5,535,963 5,500,637 5,545,653 21915459.59
B RPS Procurement Quantity Requirement (%) 0.3575 0.385 0.4125 0.44 0.399127711 C A*B Gross RPS Procurement Quantity Requirement (MWh 1906621.257 2131345.698 2269012.816 2440087.451 8747067.222 D Voluntary Margin of Over-procurement (MWh) 1,385,084 1,285,215 1,497,340 1,509,405 5677044.502 E C+D Net RPS Procurement Need (MWh) 3,291,705 3,416,561 3,766,353 3,949,493 14424111.72 RPS-Eligible Procurement New Field
Fa Risk-Adjusted RECs from Online Generation (MWh 3,424,705 3,439,018 3,997,424 4,319,508 15180655 Faa Forecast Failure Rate for Online Generation (%) #DIV/0! Fb Risk-Adjusted RECs from RPS Facilities in Development (MWh) 0 Fbb Forecast Failure Rate for RPS Facilities in Development (%) #DIV/0! Fc Pre-Approved Generic RECs (MWh) 0
Fd Executed REC Sales (MWh) 133,000 22,457 231,412 231,412 618281 F Fa+Fb+Fc-Fd Total RPS Eligible Procurement (MWh) 3,291,705 3,416,561 3,766,012 4,088,096 14562374 F0 Category 0 RECs 585,554 525,681 1111235
F1 Category 1 RECs 3,084,578 3,350,361 3,180,799 3,793,827 13409565 F2 Category 2 RECs 207,127 39,000 246127
F3 Category 3 RECs - 27,200 27200
Gross RPS Position (Physical Net Short)
Ga F-E Annual Gross RPS Position (MWh) 0 - (341) 138,603 138262.2758 Gb F/A Annual Gross RPS Position (%) 0.617209387 0.617157501 0.684650143 0.737171219 0.664479517 Application of Bank
Ha J-Hc (from previous CP) Existing Banked RECs above the PQR 0 Hb RECs above the PQR added to Bank 0
Hc Non-bankable RECs above the PQR 0
H Ha+Hb Gross Balance of RECs above the PQR 0 0 0 0 0
Ia Planned Application of RECs above the PQR towards RPS Compliance 0 Ib Planned Sales of RECs above the PQR 0
J H-Ia-Ib Net Balance of RECs above the PQR 0 0 0 0 0
J0 Category 0 RECs 0
J1 Category 1 RECs 0
J3 Category 3 Bundled RECs (Non-CBA Utilities Only)* 0
Expiring Contracts
K RECs from Expiring RPS Contracts (MWh) 815,227 1,294,994 1,048,666 1,671,826 4830712.51 Net RPS Position (Optimized Net Short)
La Ga+Ia-Ib-Hc Annual Net RPS Position after Bank Optimization0 0 -341 138603.2758 138262.2758 Lb (F+Ia-Ib-Hc)/A Annual Net RPS Position after Bank Optimization (%0.617209387 0.617157501 0.684650143 0.737171219 0.664479517 Note: All values are to be input in MWhs
*D.17-11-037 provides for utilities serving load in areas outside California Independent System Operator Balancing Authority (Non-CBA Utilities) to bank excess bundled PCC3 RECs Marin Clean Energy (MCE)
LSE Name:

Date Filed: 6/30/25
Variable Calculation Item
Forecast Year
Annual RPS Requirement
A Total Retail Sales (MWh)
B RPS Procurement Quantity Requirement (%)
C A*B Gross RPS Procurement Quantity Requirement (MWh
D Voluntary Margin of Over-procurement (MWh)
E C+D Net RPS Procurement Need (MWh)
RPS-Eligible Procurement
Fa Risk-Adjusted RECs from Online Generation (MWh
Faa Forecast Failure Rate for Online Generation (%)
Fb Risk-Adjusted RECs from RPS Facilities in Devel
Fbb Forecast Failure Rate for RPS Facilities in Developmen Fc Pre-Approved Generic RECs (MWh)
Fd Executed REC Sales (MWh)
F Fa+Fb+Fc-Fd Total RPS Eligible Procurement (MWh)
F0 Category 0 RECs
F1 Category 1 RECs
F2 Category 2 RECs
F3 Category 3 RECs
Gross RPS Position (Physical Net Short)
Ga F-E Annual Gross RPS Position (MWh)
Gb F/A Annual Gross RPS Position (%)
Application of Bank
Ha J-Hc (from previous CP) Existing Banked RECs above the PQR Hb RECs above the PQR added to Bank
Hc Non-bankable RECs above the PQR
H Ha+Hb Gross Balance of RECs above the PQR
Ia Planned Application of RECs above the PQR toward
Ib Planned Sales of RECs above the PQR
J H-Ia-Ib Net Balance of RECs above the PQR
J0 Category 0 RECs
J1 Category 1 RECs
J3 Category 3 Bundled RECs (Non-CBA Utilities Only)*
Expiring Contracts
K RECs from Expiring RPS Contracts (MWh)
Net RPS Position (Optimized Net Short)
La Ga+Ia-Ib-Hc Annual Net RPS Position after Bank Optimization Lb (F+Ia-Ib-Hc)/A Annual Net RPS Position after Bank Optimization (% Note: All values are to be input in MWhs
*D.17-11-037 provides for utilities serving load in areas outside California Independ Marin Clean Energy (MCE) Hard-coded
2025 Forecast 2026 Forecast 2027 Forecast 2025-2027 2028 Forecast 2029 Forecast 1 2 3 CP 5 4 5
5,608,766 5,591,289 5,533,994 16734049.74 5,474,800 5,406,236

0.4667 0.4933 0.52 0.493214214 0.5467 0.5733
2617611.273 2758182.938 2877676.983 8253471.194 2993073 3099395.072 1,633,655 1,486,497 1,629,709 4749860.942 1,770,858 1,902,933 4,251,267 4,244,680 4,507,386 13003332.14 4,763,931 5,002,328 4,004,716 2,889,168 3,461,443 10355326.88 2,929,534 2,923,263 10% 10% 10% 0.1 10% 10%
305,115 562,751 563,105 1430970.31 720,171 717,374
10% 10% 10% 0.1 10% 10%
0 0
4,309,831 3,451,919 4,024,547 11786297.19 3,649,706 3,640,637 0 4,309,831 3,451,919 4,024,547 11786297.19 3,649,706 3,640,637 0 0
58564.01105 -792760.3727 -482838.5837 -1217034.945 -1114225.631 -1361691.3

0.768409734 0.617374462 0.727240981 0.704330235 0.666637319 0.673414407 0 0 0
0 0
0 0 0 0 0 0
0 0
0 0 0 0 0 0
0 0
0 1,273,100 591,232 900,000 2764332 - 184
58564.01105 -792760.3727 -482838.5837 -1217034.945 -1114225.631 -1361691.3

0.768409734 0.617374462 0.727240981 0.704330235 0.666637319 0.673414407 LSE Name:

Date Filed: 6/30/25
Variable Calculation Item
Forecast Year
Annual RPS Requirement
A Total Retail Sales (MWh)
B RPS Procurement Quantity Requirement (%)
C A*B Gross RPS Procurement Quantity Requirement (MWh
D Voluntary Margin of Over-procurement (MWh)
E C+D Net RPS Procurement Need (MWh)
RPS-Eligible Procurement
Fa Risk-Adjusted RECs from Online Generation (MWh
Faa Forecast Failure Rate for Online Generation (%)
Fb Risk-Adjusted RECs from RPS Facilities in Devel
Fbb Forecast Failure Rate for RPS Facilities in Developmen Fc Pre-Approved Generic RECs (MWh)
Fd Executed REC Sales (MWh)
F Fa+Fb+Fc-Fd Total RPS Eligible Procurement (MWh)
F0 Category 0 RECs
F1 Category 1 RECs
F2 Category 2 RECs
F3 Category 3 RECs
Gross RPS Position (Physical Net Short)
Ga F-E Annual Gross RPS Position (MWh)
Gb F/A Annual Gross RPS Position (%)
Application of Bank
Ha J-Hc (from previous CP) Existing Banked RECs above the PQR Hb RECs above the PQR added to Bank
Hc Non-bankable RECs above the PQR
H Ha+Hb Gross Balance of RECs above the PQR
Ia Planned Application of RECs above the PQR toward
Ib Planned Sales of RECs above the PQR
J H-Ia-Ib Net Balance of RECs above the PQR
J0 Category 0 RECs
J1 Category 1 RECs
J3 Category 3 Bundled RECs (Non-CBA Utilities Only)*
Expiring Contracts
K RECs from Expiring RPS Contracts (MWh)
Net RPS Position (Optimized Net Short)
La Ga+Ia-Ib-Hc Annual Net RPS Position after Bank Optimization Lb (F+Ia-Ib-Hc)/A Annual Net RPS Position after Bank Optimization (% Note: All values are to be input in MWhs
*D.17-11-037 provides for utilities serving load in areas outside California Independ Marin Clean Energy (MCE)
2030 Forecast 2028-2030 2031 Forecast 2032 Forecast 2033 Forecast 2031-2033 6 CP 6 7 8 9 CP 7
5,450,346 16331381.78 5,494,873 5,570,366 5,593,623 16658862.05

0.6 0.573293544 0.6 0.6 0.6 0.6
3270207.674 9362675.745 3296923.755 3342219.628 3356173.845 9995317.228 2,066,802 5740594.015 2,377,358 2,406,310 2,417,628 7201296.017 5,337,010 15103269.76 5,674,282 5,748,529 5,773,802 17196613.24 2,922,115 8774912.69 2,761,848 2,747,655 2,418,151 7927653.43 10% 0.1 10% 10% 10% 0.1
715,449 2152995.12 895,223 965,321 959,998 2820541.55
10% 0.1 10% 10% 10% 0.1
0 0
0 0
3,637,565 10927907.81 3,657,070 3,712,976 3,378,149 10748194.98 0 0
3,637,565 10927907.81 3,657,070 3,712,976 3,378,149 10748194.98 0 0
0 0
-1699445.019 -4175361.95 -2017212.078 -2035553.037 -2395653.15 -6448418.265

0.667400702 0.66913553 0.665542259 0.66655873 0.603928558 0.645193828 0 0 0
0 0
0 0
0 0 0 0 0 0
0 0
0 0
0 0 0 0 0 0
0 0
0 0
0 0
150,564 150747.83 18,643 69,392 69,263 157297.5
-1699445.019 -4175361.95 -2017212.078 -2035553.037 -2395653.15 -6448418.265

0.667400702 0.66913553 0.665542259 0.66655873 0.603928558 0.645193828 LSE Name:

Date Filed: 6/30/25
Variable Calculation Item
Forecast Year
Annual RPS Requirement
A Total Retail Sales (MWh)
B RPS Procurement Quantity Requirement (%)
C A*B Gross RPS Procurement Quantity Requirement (MWh
D Voluntary Margin of Over-procurement (MWh)
E C+D Net RPS Procurement Need (MWh)
RPS-Eligible Procurement
Fa Risk-Adjusted RECs from Online Generation (MWh
Faa Forecast Failure Rate for Online Generation (%)
Fb Risk-Adjusted RECs from RPS Facilities in Devel
Fbb Forecast Failure Rate for RPS Facilities in Developmen Fc Pre-Approved Generic RECs (MWh)
Fd Executed REC Sales (MWh)
F Fa+Fb+Fc-Fd Total RPS Eligible Procurement (MWh)
F0 Category 0 RECs
F1 Category 1 RECs
F2 Category 2 RECs
F3 Category 3 RECs
Gross RPS Position (Physical Net Short)
Ga F-E Annual Gross RPS Position (MWh)
Gb F/A Annual Gross RPS Position (%)
Application of Bank
Ha J-Hc (from previous CP) Existing Banked RECs above the PQR Hb RECs above the PQR added to Bank
Hc Non-bankable RECs above the PQR
H Ha+Hb Gross Balance of RECs above the PQR
Ia Planned Application of RECs above the PQR toward
Ib Planned Sales of RECs above the PQR
J H-Ia-Ib Net Balance of RECs above the PQR
J0 Category 0 RECs
J1 Category 1 RECs
J3 Category 3 Bundled RECs (Non-CBA Utilities Only)*
Expiring Contracts
K RECs from Expiring RPS Contracts (MWh)
Net RPS Position (Optimized Net Short)
La Ga+Ia-Ib-Hc Annual Net RPS Position after Bank Optimization Lb (F+Ia-Ib-Hc)/A Annual Net RPS Position after Bank Optimization (% Note: All values are to be input in MWhs
*D.17-11-037 provides for utilities serving load in areas outside California Independ Marin Clean Energy (MCE)
2034 Forecast 2035 Forecast
10 11
5,630,580 5,668,684

0.6 0.6
3378348.074 3401210.202
2,433,765 2,450,396
5,812,113 5,851,607
2,348,510 2,348,338
10% 10%
955,816 952,486
10% 10%
3,304,326 3,300,824
3,304,326 3,300,824
-2507786.926 -2550783.098

0.586853635 0.582291021
0 0 0
0 0
- -
-2507786.926 -2550783.098

0.586853635 0.582291021
Appendix D
Project Development Status Update
(Public Version)
Reporting LSE Name RPS Contract ID Project Name Technology Type Project Development Phase City County State Zip Code Latitude Marin Clean Energy (MCE) MCE50001 Daggett Solar Hybrid Post-Construction Daggett San BernardinoCA 92327 34.8686 Marin Clean Energy (MCE) MCE50007
Golden Fields Solar
IV, LLC Hybrid Post-Construction Rosamond Kern CA 93560 34.8344 Marin Clean Energy (MCE) MCE60001
Strauss Wind
Project Wind Post-Construction Lompoc Santa Barbara CA 93436 34.34.53 Marin Clean Energy (MCE) MCE30003 Humboldt House Geothermal Pre-Construction Pershing Pershing NV 89418 118.55 Marin Clean Energy (MCE) MCE30001 Geysers (7MW) Geothermal Construction NA Sonoma / Lake CA 95425 38.7749 Marin Clean Energy (MCE) Key Pre-Construction Fresno CA Marin Clean Energy (MCE) Cormorant Pre-Construction Daly City San Mateo CA Marin Clean Energy (MCE) Corby Pre-Construction Vacaville Solano CA Marin Clean Energy (MCE) MCE50177 Allium Hybrid Pre-Construction Hollister San Benito CA 95023 36.9178 Marin Clean Energy (MCE) MCE 50008 Conflitti Solar PV - Ground mount Construction Firebaugh Fresno CA 93622 36.628 Marin Clean Energy (MCE) MCE50009 Conflitti jr. Solar PV - Ground Mount Construction Firebaugh Fresno CA 93622 36.628 Marin Clean Energy (MCE) MCE50113
Fallon Two Rock
Rd Solar Solar PV - Ground Mount Post-Construction Tomales Marin CA 94952 38.2795 Marin Clean Energy (MCE) MCE50010 Ranch Sereno Solar PV - Ground mount Pre-Construction Byron Contra Costa CA 94514 37.8731 Reporting LSE Name RPS Contract ID Project Name
Marin Clean Energy (MCE) MCE50001 Daggett Solar
Marin Clean Energy (MCE) MCE50007
Golden Fields Solar

IV, LLC
Marin Clean Energy (MCE) MCE60001
Strauss Wind
Project
Marin Clean Energy (MCE) MCE30003 Humboldt House
Marin Clean Energy (MCE) MCE30001 Geysers (7MW)
Marin Clean Energy (MCE) Key
Marin Clean Energy (MCE) Cormorant
Marin Clean Energy (MCE) Corby
Marin Clean Energy (MCE) MCE50177 Allium
Marin Clean Energy (MCE) MCE 50008 Conflitti
Marin Clean Energy (MCE) MCE50009 Conflitti jr.

Marin Clean Energy (MCE) MCE50113
Fallon Two Rock
Rd Solar
Marin Clean Energy (MCE) MCE50010 Ranch Sereno
Longitude Contract Length (Years) Contract Execution Date (mm/dd/yyyy)
Contract Start Date
(mm/dd/yyyy)
Contract End Date
(mm/dd/yyyy)
-116.8029 15 9/25/20
-118.3003 15 2/4/22
130.21.25 15 10/19/18

41.59 20 11/22/22
122.7553 20 2/28/23
15 10/20/23
15 3/8/24
15 10/20/23
-121.4301 20 2/14/25
-120.568 20 3/20/22
-120.568 20 3/20/22
-122.8663 20 4/5/21
-121.6258 20 2/23/22
Reporting LSE Name RPS Contract ID Project Name
Marin Clean Energy (MCE) MCE50001 Daggett Solar
Marin Clean Energy (MCE) MCE50007
Golden Fields Solar

Marin Clean Energy (MCE) MCE50113
Fallon Two Rock
Rd Solar
Marin Clean Energy (MCE) MCE50010 Ranch Sereno
Contract Capacity Expected Annual Generation Total Contract Volume Commercial Operation Date (COD)
110 342,577 4,962,640 8/25/23
100 322,635 3/1/25

93.35 290,400 4,356,000 12/22/23
20 158,000 3,318,000 2/1/28
7 61,320 1226400 6/1/25
35 6/1/27
188 6/1/26
100 4/1/27
110 276,374 5,223,472 5/1/31

4.4 12,254 232,612 3/31/26

0.26 668 12,680 3/31/26

0.96 1,899 37,980 1/29/24
2 5,649 107,774 2/22/24
Reporting LSE Name RPS Contract ID Project Name
Marin Clean Energy (MCE) MCE50001 Daggett Solar
Marin Clean Energy (MCE) MCE50007
Golden Fields Solar

Marin Clean Energy (MCE) MCE50113
Fallon Two Rock
Rd Solar
Marin Clean Energy (MCE) MCE50010 Ranch Sereno
Transmission Status Storage: Rated Power
(MW)
Storage: Capacity
(MWh)
complete 60 240
complete 92 368
complete
in development
complete
in development 35 280
in development 188 752
in development 100 400
in development 110 440
distribution
distribution
distribution
distribution 0.8 3.2
Reporting LSE Name RPS Contract ID Project Name
Marin Clean Energy (MCE) MCE50001 Daggett Solar
Marin Clean Energy (MCE) MCE50007
Golden Fields Solar

Marin Clean Energy (MCE) MCE50113
Fallon Two Rock
Rd Solar
Marin Clean Energy (MCE) MCE50010 Ranch Sereno
Project Notes
Appendix E
Cost Quantification
(Public Version)
LSE Name: Marin Clean Energy (MCE) Input Required No Input Required Date Filed: 6/30/25
1 Executed RPS-Eligible Contracts by Technology Type*
(Purchases and Sales)
T1_2022 T1_2023 T1_2024
2 Biogas: Digester Gas $41,389
3 Biogas: Landfill Gas $7,961,327 $8,197,853 $11,133,658 4 Biodiesel
5 Biomass $19,794,125 $8,758,574 $5,176,013
6 Muni Solid Waste
7 Geothermal $24,698,751 $13,894,201 $7,877,750
8 Small Hydro (Non-UOG) $12,788,238 $24,382,556 $15,936,503 9 Conduit Hydro
10 Water Supply / Conveyance
11 Ocean Wave
12 Ocean Thermal
13 Tidal Current
14 Solar PV (Non-UOG) $67,758,249 $171,242,881 $180,442,243 15 Solar Thermal $3,681,646
16 Wind $87,597,850 $76,919,773 $96,029,278
17 Unbundled RECs (REC Only) $149,600
18 Various (Index Plus REC)***
19 Fuel Cell
20 Linear Generator
21 UOG: Small Hydro $5,728,906
22 UOG: Solar PV $23,407,696
23 UOG: Other $978,023
24 Executed REC Sales (Revenue) $3,063,500
25 Total RPS-Eligible Procurement and Generation Net Cost 251522300.6 303395837 316595444.8 26 Total Retail Sales (MWh) 5,535,963 5,500,637 5,545,653 27 Incremental Rate Impact 4.543424647 5.515649003 5.708893575 Table 1: Cost Quantification (Actual Net Costs, $) Actual RPS-Eligible Procurement and Generation Net Costs ($) LSE Name: Marin Clean Energy (MCE) Input Required No Input Required Date Filed: 6/30/25
1 Executed But Not Approved RPS-Eligible Contracts (Purchases and Sales)**
T2_2025_EBNA T2_2026_EBNA T2_2027_EBNA T2_2028_EBNA T2_2029_EBNA T2_2030_EBNA T2_2031_EBNA T2_2032_EBNA T2_2033_EBNA T2_2034_EBNA T2_2035_EBNA 2 Biogas: Digester Gas
3 Biogas: Landfill Gas
4 Biodiesel
5 Biomass
6 Muni Solid Waste
7 Geothermal
8 Small Hydro (Non-UOG)
9 Conduit Hydro
10 Water Supply / Conveyance
11 Ocean Wave
12 Ocean Thermal
13 Tidal Current
14 Solar PV (Non-UOG)
15 Solar Thermal
16 Wind
17 Unbundled RECs (REC Only)
18 Various (Index Plus REC)***
20 Fuel Cell
21 Linear Generator
22 UOG: Small Hydro
23 UOG: Solar PV
24 UOG: Other
25 Executed REC Sales (Revenue)
26 Total Executed But Not Approved RPS-Eligible Procurement and Generation Cost
0 0 0 0 0 0 0 0 0 0 0
27 Total Retail Sales (MWh) 5,608,766 5,591,289 5,533,994 5,474,800 5,406,236 5,450,346 5,494,873 5,570,366 5,593,623 5,630,580 5,668,684 28 Incremental Rate Impact 0 0 0 0 0 0 0 0 0 0 0
29 Executed RPS-Eligible Contracts (Purchases and Sales)**** T2_2025_EAA T2_2026_EAA T2_2027_EAA T2_2028_EAA T2_2029_EAA T2_2030_EAA T2_2031_EAA T2_2032_EAA T2_2033_EAA T2_2034_EAA T2_2035_EAA 30 Biogas: Digester Gas
31 Biogas: Landfill Gas 9,863,658 9,887,048 9,936,058 9,028,305 7,113,050 3,689,886 2,583,467 2,583,467 32 Biodiesel
33 Biomass
34 Muni Solid Waste
35 Geothermal 82,657,815 82,464,536 82,464,536 82,464,536 82,689,728 82,465,550 82,434,651 82,465,550 36 Small Hydro (Non-UOG) 1,744,637 1,742,347 1,742,347 1,742,347 1,744,637 1,742,347 1,742,347 1,742,347 37 Conduit Hydro
38 Water Supply / Conveyance
39 Ocean Wave
40 Ocean Thermal
41 Tidal Current
42 Solar PV (Non-UOG) 85,279,767 85,191,479 85,197,082 93,961,713 97,486,718 82,758,712 79,946,435 79,906,928 43 Solar Thermal
44 Wind 30,243,448 30,165,212 30,135,734 23,528,618 23,599,481 23,529,442 23,533,128 23,533,381 45 Unbundled RECs (REC Only)
47 Various (Index Plus REC)***
48 Fuel Cell
49 Linear Generator
50 UOG: Small Hydro
51 UOG: Solar PV
52 UOG: Other
53 Executed REC Sales (Revenue)
54 Total Executed and Approved RPS-Eligible Procurement and Generation Cost
209789326.2 209450622.4 209475757.8 210725520.3 212633613.7 194185936.7 190240028.2 190231672.6 55 Total Retail Sales (MWh) 5,608,766 5,591,289 5,533,994 5,474,800 5,406,236 5,450,346 5,494,873 5,570,366 5,593,623 5,630,580 5,668,684 56 Incremental Rate Impact 3.831908699 3.874241232 3.843347801 3.834948017 3.817228741 3.471559203 3.378693209 3.355835035 57 Total RPS-Eligible Procurement and Generation Cost 209789326.2 209450622.4 209475757.8 210725520.3 212633613.7 194185936.7 190240028.2 190231672.6 58 Total Incremental Rate Impact 3.831908699 3.874241232 3.843347801 3.834948017 3.817228741 3.471559203 3.378693209 3.355835035 *Note: Technology definitions are given in the PCC Classification Handbook located in the RPS Compliance Reporting section of: https://www.cpuc.ca.gov/RPSComplianceReporting/ **Note: For contracts that have been executed but still require formal approval (CPUC or other formal approval process) for purchases and sales. ***Note: The "Various" technology type is to be used in the case of contracts encompassing multiple facilities where the generation type is not yet known ****Note: For IOUs and SMJUs: Include all executed contracts that required CPUC approval. For CCAs and ESPs: Include all executed contracts that have been approved through relevant formal approval processes.

Table 2: Cost Quantification (Forecast Costs and Revenues, $) Forecast RPS-Eligible Procurement Costs and Revenues ($) LSE Name: Marin Clean Energy (MCE) Input Required No Input Required Date Filed: 6/30/25
1 Technology Type* (Procurement / Generation and Sales) T3_2022 T3_2023 T3_2024 2 Biogas: Digester Gas 410
3 Biogas: Landfill Gas 80,148 91,513 113,004
4 Biodiesel
5 Biomass 199,046 130,185 50,940
6 Muni Solid Waste
7 Geothermal 271,560 154,515 95,839
8 Small Hydro (Non-UOG) 142,322 418,173 256,614
9 Conduit Hydro
10 Water Supply / Conveyance
11 Ocean Wave
12 Ocean Thermal
13 Tidal Current
14 Solar PV (Non-UOG) 1,330,970 2068961 2,613,960
15 Solar Thermal 83,960
16 Wind 1,003,289 1,134,077 1,189,151
17 Unbundled RECs (REC Only) 27,200
18 Various (Index Plus REC)***
19 Fuel Cell
20 Linear Generator
21 UOG: Small Hydro 57,071
22 UOG: Solar PV 233,242
23 UOG: Other 9,800
24 Executed REC Sales (MWh) 22,457 231,412 231,412
25 Total RPS Eligible Procurement (MWh) 3416561 3766012 4088096 Table 3: Cost Quantification (Actual Procurement / Generation and Sales, MWh) Actual RPS-Eligible Procurement / Generation and Sales (MWh) LSE Name: Marin Clean Energy (MCE) Input Required No Input Required Date Filed: 6/30/25
1 Executed But Not Approved RPS-Eligible Contracts (Purchases and Sales) **
T4_2025_EBNA T4_2026_EBNA T4_2027_EBNA T4_2028_EBNA T4_2029_EBNA T4_2030_EBNA T4_2031_EBNA T4_2032_EBNA T4_2033_EBNA T4_2034_EBNA T4_2035_EBNA 2 Biogas: Digester Gas
3 Biogas: Landfill Gas
4 Biodiesel
5 Biomass
6 Muni Solid Waste
7 Geothermal
8 Small Hydro (Non-UOG)
9 Conduit Hydro
10 Water Supply / Conveyance
11 Ocean Wave
12 Ocean Thermal
13 Tidal Current
14 Solar PV (Non-UOG)
15 Solar Thermal
16 Wind
17 Unbundled RECs (REC Only)
18 Various (Index Plus REC)***
20 Fuel Cell
21 Linear Generator
22 UOG: Small Hydro
23 UOG: Solar PV
24 UOG: Other
25 Executed REC Sales (MWh)
26 Total Executed But Not Approved RPS-Eligible Procurement 0 0 0 0 0 0 0 0 0 0 0 27 Executed and Approved RPS-Eligible Contracts (Purchases and Sales) **** T4_2025_EAA T4_2026_EAA T4_2027_EAA T4_2028_EAA T4_2029_EAA T4_2030_EAA T4_2031_EAA T4_2032_EAA T4_2033_EAA T4_2034_EAA T4_2035_EAA 28 Biogas: Digester Gas
29 Biogas: Landfill Gas 103,437 103,437 103,437 103,695 103,437 103,437 93,926 74,553 39,748 30,394 30,394 30 Biodiesel
31 Biomass
32 Muni Solid Waste
33 Geothermal 123,559 148,913 575,013 1,097,738 1,095,170 1,095,170 1,095,170 1,098,161 1,095,184 1,094,774 1,095,184 34 Small Hydro (Non-UOG) 160,171 237,071 37,071 37,120 37,071 37,071 37,071 37,120 37,071 37,071 37,071 35 Conduit Hydro
36 Water Supply / Conveyance
37 Ocean Wave
38 Ocean Thermal
39 Tidal Current
40 Solar PV (Non-UOG) 2,053,637 1,993,444 2,589,957 1,840,620 1,835,850 1,833,451 2,013,115 2,084,114 1,788,345 1,724,222 1,720,306 41 Solar Thermal
42 Wind 869,026 769,053 719,069 570,533 569,108 568,435 417,787 419,028 417,801 417,865 417,869 43 Unbundled RECs (REC Only)
45 Various (Index Plus REC)*** 1,000,000 200,000
46 Fuel Cell
47 Linear Generator
48 UOG: Small Hydro
49 UOG: Solar PV
50 UOG: Other
51 Executed REC Sales (MWh)
52 Total Executed and Approved RPS-Eligible Procurement 4309830.69 3451919.13 4024547.37 3649705.8 3640637.18 3637564.83 3657070.14 3712976.12 3378148.72 3304326.41 3300823.6 53 Total RPS Eligible Procurement (MWh) 4309830.69 3451919.13 4024547.37 3649705.8 3640637.18 3637564.83 3657070.14 3712976.12 3378148.72 3304326.41 3300823.6 *Note: Technology definitions are given in the PCC Classification Handbook located in the RPS Compliance Reporting section of: https://www.cpuc.ca.gov/RPSComplianceReporting/ **Note: For contracts that have been executed but still require formal approval (CPUC or other formal approval process) for purchases and sales. ***Note: The "Various" technology type is to be used in the case of contracts encompassing multiple facilities where the generation type is not yet known ****Note: For IOUs and SMJUs: Include all executed contracts that required CPUC approval. For CCAs and ESPs: Include all executed contracts that have been approved through relevant formal approval processes.

Table 4: Cost Quantification (Forecast Procurement / Generation and Sales, MWh) Forecast RPS-Eligible Procurement / Generation and Sales (MWh) STATE OF CALIFORNIA GAVIN NEWSOM, Governor

PUBLIC UTILITIES COMMISSION
505 VAN NESS AVENUE

1 June 30, 2025
Advice Letter 20-E/20-G et. al.

Lujuana Medina
Division Manager, Environmental Initiatives
County of Los Angeles
On behalf of Southern California Regional Energy Network SUBJECT: Tier 2 Advice Letter Filed by Southern California Regional Energy Network on Behalf of the Energy Efficiency Portfolio Administrators for Program Overlap Analysis Dear Ms. Medina,
Advice Letter 20-E/20-G et al. is approved effective June 11, 2025.

Southern California Regional Energy Network (SoCalREN) submitted Advice Letter 20-E/20-G et al. requesting approval of compliance with Ordering Paragraph 32 of D.23-06-055. The Public Advocates Office of the California Public Utilities Commission (Cal Advocates) protested the advice letter on the grounds that the advice letter does not comply with OP 32 because the analysis of substantially similar programs is insufficient, the advice letter does not define program precedence, and it does not describe mitigation effectiveness. Pacific Gas and Electric (PG&E) filed comments, agreeing with the need for further assessment to determine program precedence, but arguing that the Commission should approve the advice letter. Bay Area Regional Energy Network, Inland Regional Energy Network, Marin Clean Energy, SoCalREN, Tri-County Regional Energy Network, Pacific Gas & Electric, Southern California Edison, Southern California Gas, and San Diego Gas and Electric submitted replies to the protest arguing that the advice letter complies with applicable Commission policy and guidance.

Attachment 1 provides more detail on the advice letter background, protest, comments, and Energy Division disposition.

Sincerely,
Leuwam Tesfai
Deputy Executive Director for Energy and Climate Policy/ Director, Energy Division
California Public Utilities Commission
cc:

Service List R.13-11-005
Service List R.25-04-010
ED Tariff Unit, CPUC
Jacob Coby Rudolph, Energy Division, CPUC
2 Lujuana Medina, [email protected]
Shelly Lyser. [email protected]
Alejandra Tellez, [email protected]
Jane Elias, [email protected]
Casey Dailey, [email protected]
Wade Stano, [email protected],
Karyn Gansecki, [email protected],
Greg Anderson, [email protected]
Gary Lenart, [email protected]
Sidney Dietz, c/o Megan Lawson, PG&E
Connor Flanigan, [email protected]
PG&E Tariff Unit, [email protected], PG&E
SCE Tariff Unit, [email protected], SCE
SoCalGas Tariff Unit, [email protected]
SDG&E Tariff Unit, [email protected], SDG&E
3 ATTACHMENT 1
Background
Ordering Paragraph (OP) 32 of D.23-06-055 directs the Portfolio Administrators (PAs) to provide information on substantively similar programs and steps that they have taken and will take to mitigate or minimize ratepayer risk of program overlap and duplication in a Tier 2 advice letter no later than September 1, 2024. On August 16, 2024, SoCalREN, on behalf of the PAs, requested and was granted a one-month extension for the advice letter. On October 1, 2024, SoCalREN filed Advice Letter 20-E/20-G et al. requesting approval of compliance with OP 32 of D.23-06-055. The advice letter, hereafter called the Joint AL, was filed as SoCalREN AL 20-E/20-G, BayREN AL 27-E, I-Ren AL 6 E/6-G, MCE AL 83-E, PCG AL 4980-E/7390-G, SDGE AL 4523-E/3351-G, SCE AL 5383-E, SoCalGas AL 6375-G, and TC REN AL 12-E/11-G. The Joint AL includes as an attachment a report authored by the PAs, herein called the OP 32 Report, in adherence with the six requirements of the OP. PG&E, SCE, and SDG&E included a statement in the Joint AL that they plan to further analyze measure-level overlap and the concept of program precedence.

Section 9.1 of D.23-06-055 highlights a call by the Public Advocates Office at the California Public Utilities Commission (Cal Advocate) for an assessment of duplication among statewide, PA-implemented and third party-implemented programs and recommends that the Commission provide guidance for the prioritization of programs. In rebuttals to D.23-06-055, BayREN, MCE, PG&E, SCE, SDG&E, SoCalREN, and 3C-REN disagreed with Cal Advocates’ request. BayREN, 3C-REN, MCE, CEDMC and SoCalREN recommended that the Joint Cooperation Memo process and other established PA coordination efforts are sufficient to resolve these issues. SCE countered Cal Advocates’ identification of some of their programs as duplicative. However, SCE argued that the Commission needs to provide guidance regarding program prioritization. The Commission concluded in D.23-06-055 that an assessment using specific examples and scenarios could be informative and stated that they “are not wedded to establishing formal guidance if the PAs demonstrate they have a process or protocol to, among themselves, effectively mitigate or minimize ratepayer risks associated with duplicative or overlapping program”.1 Accordingly, OP 32 of D.23-06-055 orders the PAs to file an advice letter that provides:
a. A comprehensive list of any substantively similar ratepayer-funded energy efficiency programs among the PAs.
b. A clear statement of the issues or problems that result from program offerings identified in Item (a).
c. Definitions or clarifications of any jargon that PAs suggest specifying, in order to have a shared understanding of the issues or problems associated with substantively similar ratepayer-funded energy efficiency programs among different PAs. For example, the joint advice letter should propose definitions for “overlap,” “duplication,” and “precedence.” d. Description of the risk to ratepayers of ratepayer-funded energy efficiency programs that “overlap” or are otherwise “duplicative” (as defined in response to Item (c), above) in some substantive way. What is the estimated dollar value of the risk? Describe how the value was calculated or assessed.
e. Description of the actions, measures, etc. that PAs have taken thus far to identify and mitigate or minimize risks to ratepayers of substantively similar ratepayer-funded energy efficiency 1 D.23-06-055 at 87
4 programs among different PAs, and any other issues identified in response to Item (b).

Include, for instance, any agreed-upon criteria for determining program “overlap,” “duplication,” and/or “precedence,” and what steps have been taken by each PA in cases where “overlap” or “duplication” was identified. Explain the effectiveness of each of these measures, actions, etc. in mitigating ratepayer risks, and identify and describe what issues remain unresolved.
f. Description of how the PAs will effectively mitigate or minimize ratepayer risks associated with similar ratepayer-funded energy efficiency programs among different PAs through the JCM or any other agreed-upon process or protocol.2
The PAs request Commission approval that the information in their OP 32 Report, attached to the Joint AL, complies with the six requirements (above) in OP 32 of D.23-06-055. The report outlines information on 27 programs that are substantively similar, as well as the measures PAs implement to mitigate or minimize the risk of program overlap or duplication for ratepayers.

The PAs believe that the Joint AL complies with OP 32(a) by providing a list (Table 12 of the report), and in an excel spreadsheet in an Appendix to the report. The PAs identified 27 programs that met their agreed-upon criteria of substantially similar or duplicative programs. OP 32(b) orders that the PAs provide a clear statement of the issues or problems that result from these programs.

The PAs state, “Generally, the potential risks of program duplication include inefficiencies in resource allocation, confusion among customers, and increased costs due to duplication of efforts.

Duplicative programs may also struggle with clear delineation of responsibilities, leading to gaps in service delivery or redundant work. Additionally, program overlap can result in competition for the same funding sources and beneficiaries, which might undermine the effectiveness of the programs involved.”3 For compliance with OP 32(c), the PAs provide agreed-upon definitions to address substantially similar energy efficiency programs among different PAs. They agreed to define four terms: “similar”, “program overlap”, “substantially similar”, and “program duplication”. 4 They met
multiple times in 2024 and developed definitions for each term.5 OP 32(d) orders the PAs to describe the risk to ratepayers of rate-payer-funded energy efficiency programs that overlap or are otherwise duplicative, using their definitions of these terms. The OP instructs the PAs to include a dollar amount for the risk and explain their method for the valuation.

The PAs explain that “potential ratepayer risk can be thought of as the expenditure of ratepayer funds without maximum value provided or created.”
6 Using their authorized budgets, the PAs
identified approximately $4,900,000 in potential annual ratepayer risk. However, if mitigation strategies are taken into account, the risk is lowered by 69% to approximately $1,500,000 in potential annual risk, according to the PAs.

OP 32(e) orders the PAs to describe the actions they have taken to mitigate risks to ratepayers of substantively similar ratepayer-funded energy efficiency programs among different PAs. The PAs agreed upon four types of Mitigation Actions that address ratepayer risk and identified which 2 Ibid at 129-130
3 OP 32 Report at 43
4 Ibid at 19-21
5 See OP 32 Table 7 at 20
6 OP 32 Report at 37
5 Mitigation Actions apply to each of the 27 programs identified as Substantively Similar or Duplicative. In their advice letter, the PAs describe the four types of mitigation strategies as:

1. Cross PA & Program Coordination: e.g., JCM, PA Sector Coordination, including sharing data between programs for marketing & implementation transparency.

2. Program engages in Community-Based Initiatives: e.g., Collaborate with local organizations to conduct community assessments and align program efforts with local needs, avoiding unnecessary overlap in service delivery.

3. Customer Education & Coordination and/or Joint Program Initiatives (JPI): e.g., Educate stakeholders & participants to help make informed decisions as to which programs to participate in; JPI - Coordinate training sessions, workshops, events, etc.

4. Programmatic Actions including Implementation Plan updates; have developed program protocols and decision trees; assessment of core program offerings relative to other similar programs; etc.7
The PAs state that the Joint AL complies with OP 32(f) by stating that the PAs will continue to use the processes and strategies discussed in their respective Joint Cooperation Memos to continue ensuring effective mitigation of potential ratepayer risk associated energy efficiency programs, particularly those that potentially are Substantively Similar or Duplicative. The Southern California PAs, SoCalREN, SCE, SoCalGas, I-REN, and 3C-REN, have recurring sector-specific Portfolio Administrator Sector Coordination meetings (PASC), where they coordinate to ensure that their programs do not overlap or duplicate each other.8
Protest
Cal Advocates requested an extension of time to protest, which the Commission granted, so that they could issue a data request to SoCalREN and conduct a more detailed analysis of program overlap. Cal Advocates filed a timely protest on November 4, 2024. In the protest, Cal Advocates asserts that the definition of substantially similar is too narrow in the Joint AL, leading to an incomplete list of potentially overlapping or duplicative programs and a risk lower than if it included more programs. Cal Advocates also argues that the Joint AL fails to comply with the Commission’s order in OP 32 because it does not include a definition of precedence.

Cal Advocates asserts that the four types of mitigation strategies in the Joint AL do not explain how the PAs have effectively mitigated and will continue to mitigate the risk to ratepayers from duplicative programs. Cal Advocates issued a data request to the PAs for workpapers for more information. Cal Advocates says in the protest that the workpapers show the mitigation by program, but they do not analyze the effectiveness and fail to explain how PAs will mitigate overlap and/or duplication in the future.

Cal Advocates claims that the Joint AL does not analyze the potential overlap of several PG&E programs with programs administered by BayREN and MCE, which are in the same territory. Cal Advocates asserts that PG&E submitted implementation plans for these programs 10 days after the Joint AL was filed; therefore, Cal Advocates believes that the Joint PAs should have corrected the Joint AL through a supplemental AL for PG&E’s EmPower My Home program, and that all other programs should also be re-analyzed with the most up-to-date data to address overlap and 7 Ibid at 29
8 Ibid at 46
6 duplication. Additionally, Cal Advocates claims that the Joint AL understates the financial impact on ratepayers. They believe that the calculations should include marketing, education, and outreach costs, direct implementation non-incentives and incentive costs, and program administration.

Cal Advocates proposes that the Commission should direct the PAs to submit a supplemental advice letter to correct the errors and omissions in the Joint AL as detailed in their protest, and there should be an opportunity for the parties to protest or respond to the supplemental advice letter.

They request that the supplemental advice letter demonstrate a process or protocol that will effectively mitigate or minimize ratepayer risks associated with duplicative or overlapping programs.

Responses
PG&E filed a timely response to the Joint AL on November 4, 2024. PG&E reiterates that the Joint AL complies with OP 32. They clarify that the intention of the electric IOUs, i.e., PG&E, SCE, and SDG&E, in their joint statement is to request that the Commission wait to determine if guidance is needed until after the PAs have completed another program overlap assessment that more completely captures the potential overlap between statewide midstream and statewide/local downstream programs. They anticipate that the complexity of program implementation for overlapping programs will very likely warrant Commission guidance on program precedence. In their response, they provide the scenario that if two different programs provide the same piece of equipment, but one is midstream distribution and the other is downstream resident, does one have more right to the savings claims than the other?9
PG&E, SCE, SoCalGas, and SDG&E separately filed replies to the Cal Advocates protest on November 12, 2024.

PG&E agrees that the definition of substantially similar is too narrow to capture overlap between some programs, such as deemed or not deemed programs. They point out that this excludes statewide deemed programs from being analyzed alongside downstream Normalized Metered Energy Consumption (NMEC) programs. However, rather than requiring a revision of the existing assessment and a supplemental advice letter as Cal Advocates suggest, PG&E argues that a new assessment is needed that focuses more narrowly on statewide midstream and statewide/local downstream before the Commission decides on program precedence. PG&E agrees with Cal Advocates that up-to-date data should be used, and, again, PG&E suggests that the PAs should conduct a new overlap assessment. However, they disagree with Cal Advocates that the Joint AL erred in analysis of some programs due to lack of data. For instance, PG&E supports the claim in the Joint AL that the PAs can use their Implementation Plans to determine mitigation actions for programs that do not have claims data available.

SCE acknowledges that there are different definitions of the key terms, but believes that the OP 32 Report meets the requirements of the OP and the Commission should not require a supplemental AL. SCE re-iterates that the electric IOUs plan to continue to analyze program overlap. SCE asserts that managing ratepayer risk is an ongoing process, and the PAs plan to continue further analysis.

SCE urges that the Commission approve the Joint AL and would like the Commission to wait to provide guidance on program precedence until after the electric IOU PAs’ next assessment is complete.
9 PG&E Response at 6-7
7 SoCalGas asserts in response to Cal Advocates’ protest that some SoCalGas programs were not on the list because there are "fully operational monthly verification protocols to address such topics as duplicative program offerings, customer eligibility and double-dipping."10 SoCalGas further clarifies that Joint Cooperation Memos, recurring PA coordination meetings, and individual meetings with PAs in the same geographic area are where mitigation of risks happens.

SDG&E comments that “ultimately no duplication was identified through the analysis, however there were coordination gaps identified regarding Statewide programs” and reiterates that the electric IOUs plan to continue to analyze program overlap.11 SDG&E clarifies that San Diego REN programs were not available at the time of the OP 32 Report analysis, so they were not included, and coordination is currently taking place between SDG&E and San Diego REN.

SoCalREN requested and the Commission granted an extension of time to reply to the Cal Advocates’ protest. BayREN, I-REN, MCE, SoCalREN, and 3C-REN filed jointly on November 18, 2024. In their reply, they reiterate that the Joint AL complies with OP 32 by defining agreed-upon terms and criteria for four terms: “similar,” “program overlap,” “substantially similar,” and “program duplication”. They state that the PAs agreed upon the method for determining substantial overlap and duplication, which they say complies with the OP. Contrary to the Cal Advocates protest, they argue that the OP does not specifically order that the PAs include the term “precedence.” The Joint AL places emphasis on the OP’s requirement that the AL should define “agreed-upon criteria for determining ‘overlap,’ ‘duplication, and/or ‘precedence.”12 The RENs and MCE assert that “additional analysis to address potential midstream and downstream double dipping of incentives and double counting of savings claims should occur separately and not be required as a revision to the Joint AL.”
13 They note that existing frameworks of JCMs and coordination meetings allow the PAs to address overlap without Commission guidance. They provide examples of items discussed in monthly PA coordination meetings: customer targeting, verifying customer eligibility, and incentive double dip checks.

Additionally, the RENs and MCE state that the workpapers in response to Cal Advocates’ data request provide details on which and how the PAs applied mitigation actions to the 27 programs.

They offer that, in the future, the PAs can share the Joint Cooperation Memos and PASC meeting discussion notes regarding customer-targeting and measure-level offerings, if requested. Regarding Cal Advocates’ claim that the Joint AL should re-analyze PG&E’s EmPower My Home and other programs using more up-to-date data, the RENs and MCE state that those programs had not met the threshold of change in a program, so updating the analysis was not necessary for those programs. They reiterate that Joint Cooperation Memos and PA coordination, including monthly calls, provide ways to check for overlap and double dipping.

Energy Division Disposition
Energy Division reviewed the Joint AL, the protest from Cal Advocates, the PG&E response, and all replies to the protest and/or response. Energy Division summarizes the relevant issues into the categories below.
10 SoCalGas at 2
11 SDG&E at 2
12 RENs and MCE Reply at ii
13 Ibid at iii
8 Substantially similar programs
Cal Advocates argue that the Joint AL does not comply with OP 32 because the definition of substantially similar is too narrow. They correctly note that the PA's method identified programs that are in the same sector, have the same delivery type and program segment, are in the same IOU territory, and engage with the same audience. However, Energy Division staff determined that the method in the Joint AL to identify substantially similar programs complies with OP 32 because the OP did not specify the definition.

Program precedence
Cal Advocates claims that the Joint AL does not comply with OP 32 because the AL does not define the term “precedence”. Energy Division staff agree with the PAs who point out that the OP states, “For example [emphasis added], the joint advice letter should [emphasis added] propose definitions for “overlap,” “duplication,” and “precedence.” The PAs took the direction as a list of suggested terms, not mandatory ones.14 PG&E suggests that the specific concerns raised by Cal Advocates should be addressed through a new assessment “that more completely addresses the extent of Statewide midstream and Statewide/local downstream program overlap.”15 Energy Division staff agree that further assessment of program precedence could be warranted, but is not required for compliance with OP 32.

Mitigation to minimize or avoid overlap and duplication Cal Advocates assert that the Joint AL does not include an explanation of how mitigation was conducted. The OP 32 Report lists four categories of mitigation and states which mitigation types were applied to each program. Energy Division staff agree with Cal Advocates that an explanation could be useful to better understand the effectiveness of the various mitigation measures; however, staff finds that OP 32 did not direct the PAs to produce an analysis of methods for choosing mitigation activities and measuring their effectiveness. Staff finds that the four categories of mitigation activities are a good first step for understanding how PAs can avoid or minimize overlap or duplication of programs.

Ratepayer risk calculations
Cal Advocates protest that additional elements should have been included in the valuation of ratepayer risk. PG&E disagrees that additional elements should be included because they could be misleading. Energy Division staff finds that the Joint AL includes sufficient elements into the valuation of risk for the purpose of compliance with OP 32. This is an issue that could be further studied in a future assessment, if needed.

In Reply to Cal Advocates’ request for a supplemental AL, the RENs and MCE state, “This OP 32 effort has not only highlighted the effective mitigation strategies currently in place but also the gaps that still need to be addressed. The cross-PA coordination efforts to effectively mitigate ratepayer risk have only begun and PAs are expected to improve and increase their coordination efforts to share best practices while integrating additional strategies into their processes to more effectively minimize ratepayer risk.”
16 Consistent with the PAs, Energy Division staff agrees that the process for Joint Cooperation Memos, existing coordination meetings, and implementation plans are places 14 D.23-06-055 at 87
15 PG&E Response at 4
16 RENs and MCE Reply at v
9 where PAs will continue to discuss substantially similar programs and ways to avoid risk to ratepayers from program overlap or duplication.

Conclusion
AL 20-E/20-G et al. is approved as described in this letter.

Docket No.: A.24-10-014
Exhibit No.:

Date: June 30, 2025
Witness: Kyra J. Coyle
PREPARED DIRECT TESTIMONY OF KYRA J. COYLE

ON BEHALF OF

THE JOINT COMMUNITY CHOICE AGGREGATORS
IN PG&E’S BILLING MODERNIZATION INITIATIVE
June 30, 2025
i
1 EXECUTIVE SUMMARY OF RECOMMENDATIONS
This testimony presents the recommendations of the Joint CCAs1 2 concerning certain issues 3 in the Application of Pacific Gas and Electric Company for Approval of Its Billing Modernization 4 Initiative, submitted on October 23, 2024.
5 The Joint CCAs recommend the Commission order PG&E to adopt the following 6 modifications to its proposed BMI:
7 • Order PG&E to implement the following changes to facilitate CCAs’ 8 communications with their customers via customer bill messaging:
9 o Shorten the timeline to process changes to CCA-specific bill messaging to 10 be in line with SCE’s timeline of two business days. 11 o Design the final end-state billing system to have increased flexibility and 12 text space for messaging (in both the “swim lane” and “on-bill message” 13 portions of the bill).
14 o Limit the ability of PG&E to modify requested CCA-specific messaging. 15 o Design the end-state billing system to allow placement changes of the CCA 16 messaging (i.e., allow the “about” information to be moved from the bottom 17 right corner).
18 o Design the end-state billing system to allow CCAs to incorporate customer-19 specific messaging on customer bills (e.g., messaging specific to particular 20 customer classes, to customers who are enrolled in specific programs like 21 CARE or FERA, or to EV customers).
22 o Design the end-state billing system to allow clickable URLs in online bills, 23 CCA logos in color, and messaging in color.
24 • Order PG&E to conduct joint PG&E-CCA stakeholder workshops prior to the 25 design portion of Phase 3 of the BMI, covering: comprehensive bill redesign, 26 dynamic rate bill presentation, and any remaining implementation issues arising out 27 of the CCA bill presentation changes discussed above; 1 Acronyms and defined terms used in this Summary of Recommendations are defined within the body of this testimony.
ii
1 • Reflect all discounts that are calculated based on the total bill (i.e., CARE and 2 FERA) in a completely consistent manner and as a reduction to an eligible 3 customer’s total electric charges;
4 • Separate the PCIA as a separate line item on customers’ bills, so that it can be 5 presented in a consistent manner that reflects the kWh usage and applicable kWh 6 rate used to calculate the PCIA;
7 • Order PG&E to functionalize all BMI costs it proposes to functionalize to the 8 generation function to the distribution function instead; 9 • Reject PG&E’s proposal to recover the costs associated with the CC&B 25.1 10 upgrade as BMI costs;
11 • Order PG&E to ensure its BMI addresses certain shortcomings and persistent 12 billing problems associated with its legacy billing system, including by:
13 o Sharing certain critical billing data with CCAs.
14 o Addressing various issues with the quality of the billing data currently 15 shared with the CCAs.
16 o Dedicating more resources toward resolving CCA customer billing issues 17 and delays in a timely manner, including via a designated PG&E point of 18 contact for such issues and a semi-annual PG&E-CCA stakeholder 19 workshop on resolving outstanding technical billing issues. 20 o Clarifying, via an advice letter filing, PG&E’s plan regarding how and when 21 it will communicate with various customer groups on major upcoming 22 changes arising out of the BMI, with the constraint that PG&E must provide 23 at least three months’ notice in advance of implementation of such billing 24 changes.
25 o Remediating various issues with billing mechanics and delays related to rate 26 switch requests, inaccurate applications of bill credits, and backlogged 27 billing projects.
28 • Order PG&E to regularly track and publicly report on its billing system efficiency 29 metrics, and ensure that its BMI allows it to achieve consistent quarterly 30 improvements on these efficiency metrics;
iii
1 • With respect to the rollout of the BMI, order PG&E to: (1) commit to specific dates 2 certain for achieving implementation of its backlogged rate projects, and (2) 3 commit to a specific timeline of seven business days for resolving any CCA billing 4 and revenue delays arising out of the BMI deployment; and 5 • Order PG&E to clearly outline the BMI’s likely impact on CCA service fees and 6 commit to service fee updates post BMI implementation. iv

TABLE OF CONTENTS
EXECUTIVE SUMMARY OF RECOMMENDATIONS .......................................................... i I. INTRODUCTION AND SUMMARY OF RECOMMENDATIONS ................................. 6 II. THE COMMISSION SHOULD ORDER PG&E TO IMPLEMENT

SPECIFIC CHANGES RELATED TO THE PRESENTATION OF ITS
CUSTOMER BILLS DURING THE BMI PROCESS. ..................................................... 11 A. PG&E Should Adopt Bill Presentation Changes to Facilitate Communications Between CCAs and Their Customers. ............................................................................................ 13 B. PG&E Should Develop Dynamic Rate Presentation Collaboratively with CCAs Through a Workshop Process. ........................................................................................................ 18 C. CARE And FERA Discounts Should Be Clearly Reflected on Both Bundled and Unbundled Customer Bills by Q3 of 2026. ...................................................................... 20 D. The PCIA Should Be Broken Out as a Line Item on Bundled Customer Bills by Q3 of 2026. ................................................................................................................................. 25 III.THE COMMISSION SHOULD NOT ALLOW PG&E TO FUNCTIONALIZE ANY BMI COSTS TO THE ELECTRIC GENERATION FUNCTION. ........................ 32 IV.THE COMMISSION SHOULD NOT ALLOW PG&E TO RECOVER THE
COSTS ASSOCIATED WITH THE CC&B 25.1 UPGRADE AS BMI COSTS. ........... 40 V. THE COMMISSION SHOULD HOLD PG&E ACCOUNTABLE FOR

ENSURING THE BMI FIXES CERTAIN PERSISTENT BILLING
PROBLEMS, IMPROVES PG&E’S PERFORMANCE ON DESIGNATED

BILLING SYSTEM EFFICIENCY METRICS, AND ACHIEVES TARGET
TIMELINES FOR CRITICAL GOALS. ............................................................................ 48 A. The Commission Should Order PG&E to Ensure its BMI Investment Addresses Certain Persistent Billing System Problems. ................................................................................ 48 B. The Commission Should Order PG&E to Ensure its BMI Investment Results in Improvements on Key Billing System Efficiency Metrics. ............................................. 58 C. PG&E Should be Held Accountable for Achieving Certain Timing Targets in the BMI Rollout. ............................................................................................................................. 60 VI.THE COMMISSION SHOULD REQUIRE PG&E TO CLEARLY OUTLINE THE BMI’S LIKELY IMPACT ON CCA SERVICE FEES AND COMMIT
TO SERVICE FEE UPDATES POST-BMI IMPLEMENTATION. ............................... 62 Attachment KJC-1 – CV of Kyra J. Coyle
Attachment KJC-2 – PG&E Responses to PCE Data Requests
Attachment KJC-3 – SCE Bill Message Request Template
v

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Application of Pacific Gas and Electric Company
for Approval of Its Billing Modernization Initiative. Application 24-10-014 (Filed October 23, 2024)
Prepared Direct Testimony of Kyra J. Coyle
on behalf of the Joint Community Choice Aggregators
6 1 I. INTRODUCTION AND SUMMARY OF RECOMMENDATIONS
2 Q: Please state your name, position, and business address. 3 A: My name is Kyra Coyle. I am a Principal at NewGen Strategies and Solutions, LLC. My 4 business address is 225 Union Boulevard, Suite 450, Lakewood, Colorado 80228. 5 Q: Please describe your experience and qualifications. 6 A: I have over 15 years of experience in the utility, mining, and public accounting sectors. My 7 expertise includes utility revenue requirement analyses, strategic planning, project 8 management, contract negotiations, financial modeling, regulatory affairs, budgeting, 9 forecasting, and regulatory accounting. My rate-related projects have included studies to 10 develop retail electric, natural gas, transmission, ancillary service, standby, and special 11 contract rates. I have provided expert witness testimony before several public utility 12 commissions, including Texas, Utah, Oregon, Indiana, and Wyoming, as well as the 13 Federal Energy Regulatory Commission (FERC). A summary of my qualifications is 14 provided within Attachment KJC-1 to this testimony.
15 Q: On whose behalf are you testifying?
16 A: I am testifying on behalf of Ava Community Energy (Ava), Central Coast Community 17 Energy (3CE), CleanPowerSF, Marin Clean Energy (MCE), Peninsula Clean Energy 18 Authority (PCE), San Jose Clean Energy (SJCE), Silicon Valley Clean Energy (SVCE), and Sonoma Clean Power Authority (SCP) (collectively, the Joint CCAs).1 19 Each of these 20 community choice aggregators (CCAs) operate and provide power supply services within 21 Pacific Gas and Electric Company’s (PG&E) service territory. 22 Q: Why do the CCAs have an interest in the BMI?
23 A: Over the next five years, PG&E’s Billing Modernization Initiative (BMI) will replace the 24 utility’s aging billing system currently used to serve its electric and gas customers in the 25 areas of billing, customer service, and customer data management. By law, PG&E is 26 required to serve as the billing agent for the CCAs in its service territory, and to provide 1 PCE submitted a Protest to PG&E’s Application on November 25, 2024, and therefore has party status in this proceeding. The remainder of the Joint CCAs filed a motion for party status on June 25, 2025, which was granted on June 30, 2025.
7 “metering, billing, collection, and customer service” to CCA customers.2 1 Under this setup, 2 PG&E bills CCA customers on behalf of CCAs and handles the collection and transfer of 3 payments made by CCA customers to CCAs. Currently, more than half of PG&E’s 4 customers are unbundled and receive service from CCAs, and additional CCA expansion is expected in the next few years.3 5 Therefore, CCAs have an interest in ensuring the BMI 6 upgrades will result in billing systems and processes that are sufficient to meet CCA 7 customer needs, and are designed to equitably serve both PG&E’s bundled and unbundled 8 customers.
9 In addition, PG&E proposes to recover the costs of the various billing system 10 upgrades implemented through the BMI from all electric and gas customers within its service territory, including from the unbundled electric customers of CCAs.4 11 CCAs have 12 an interest in ensuring the BMI costs are appropriately and fairly functionalized and 13 allocated to customers because CCA customers will be responsible for part of the costs of 14 the BMI.
15 Finally, the billing agent relationship between PG&E and CCAs—coupled with 16 the fact that PG&E competes with CCAs in its service territory for electric customers— 17 compels the Joint CCAs to ensure that PG&E’s billing system and cost allocation proposals 18 do not confer an unfair competitive advantage to PG&E. 19 Q: What is the purpose of your testimony?
20 A: This testimony primarily focuses on the following issues in the March 27, 2025, Assigned Commissioner’s Scoping Memo and Ruling (Scoping Ruling):5 21 22 3. Whether the timing of the BMI is reasonable, including its phases and 23 implementation plan;
2 Cal. Pub. Util. Code § 366.2(c)(9).
3 See Community Choice Aggregation and Energy Service Provider Formation Status Report (Feb. 28, 2024), available at https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/community-choice-aggregation-and-direct-access/2024-status-report-on-community-choice-aggregation-formation.pdf?utm_source=chatgpt.com. 4 A.24-10-014, PG&E’s Prepared Testimony, Chapter 8, Table 8-1 and Table 8-2 (PG&E Testimony).
5 See A.24-10-014, Assigned Commissioner’s Scoping Memo and Ruling, p. 4 (March 27, 2025) (Scoping Ruling).
8 1 4. Whether the BMI cost is reasonable and provides benefits and savings to ratepayers. 2 This includes consideration of stranded investments in the current billing system, 3 comparison to the alternative billing upgrade approaches, and difference in costs 4 from the costs proposed in the 2023 GRC;
5 5. Whether PG&E’s proposed cost recovery treatment for its BMI is reasonable and 6 appropriate, including whether PG&E should modify its proposed cost allocation 7 and rate mechanism for recovery of the Billing Modernization Initiative costs; 8 6. Whether the BMI will include any anti-competitive design elements or have any 9 anti-competitive impacts, as well as whether the upgrades will support corrections 10 to the current bill presentation that facilitate greater transparency and foster fair 11 competition.
12 Specifically, this testimony focuses on (1) the proper presentment of rates and other 13 critical information on bundled and unbundled customer bills generated by PG&E’s billing 14 system, as upgraded through the BMI, (2) the need for greater collaboration with the CCAs 15 and other stakeholders in the design and bill presentment process going forward, (3) the 16 appropriate functionalization of certain BMI costs to electric distribution rather than to the 17 electric generation function, (4) the rejection of cost recovery for the Customer Care and 18 Billing (CC&B) 25.1 upgrade as BMI costs in light of PG&E’s extensive delay that 19 necessitated this interim step in the upgrade process, (5) the need for firm commitments 20 from PG&E on addressing certain persistent billing issues, improving certain billing 21 system efficiency metrics in its post-BMI end-state billing system, and meeting reasonable 22 timelines on various aspects of BMI implementation, and (6) PG&E’s insufficient showing 23 regarding likely changes to its CCA service fees as a result of the BMI. 24 Q: Can you summarize the Joint CCAs’ specific recommendations on these issues? 25 A: The Joint CCAs recommend the Commission order PG&E to adopt the following 26 modifications to its proposed BMI:
27 • Order PG&E to implement the following changes to facilitate CCAs’ 28 communications with their customers via customer bill messaging:
9 1 o Shorten the timeline to process changes to CCA-specific bill messaging to 2 be in line with Southern California Edison Company’s (SCE) timeline of 3 two business days.
4 o Design the final end-state billing system to have increased flexibility and 5 text space for messaging (in both the “swim lane” and “on-bill message” 6 portions of the bill).
7 o Limit the ability of PG&E to modify requested CCA-specific messaging. 8 o Design the end-state billing system to allow placement changes of the CCA 9 messaging (i.e., allow the “about” information to be moved from the bottom 10 right corner).
11 o Design the end-state billing system to allow CCAs to incorporate customer-12 specific messaging on customer bills (e.g., messaging specific to particular 13 customer classes, to customers who are enrolled in specific programs like 14 California Alternate Rates for Energy (CARE) or Family Electric Rate 15 Assistance (FERA), or to electric vehicle (EV) customers). 16 o Design the end-state billing system to allow clickable URLs in online bills, 17 CCA logos in color, and messaging in color.
18 • Order PG&E to conduct joint PG&E-CCA stakeholder workshops prior to the 19 design portion of Phase 3 of the BMI, covering: comprehensive bill redesign, 20 dynamic rate bill presentation, and any remaining implementation issues arising out 21 of the CCA bill presentation changes discussed above; 22 • Reflect all discounts that are calculated based on the total bill (i.e., CARE and 23 FERA) in a completely consistent manner and as a reduction to an eligible 24 customer’s total electric charges;
25 • Separate the Power Charge Indifference Adjustment (PCIA) as a separate line item 26 on customers’ bills, so that it can be presented in a consistent manner that reflects 27 the kilowatt-hour (kWh) usage and applicable kWh rate used to calculate the PCIA; 28 • Order PG&E to functionalize all BMI costs it proposes to functionalize to the 29 generation function to the distribution function instead; 10 1 • Reject PG&E’s proposal to recover the costs associated with the CC&B 25.1 2 upgrade as BMI costs;
3 • Order PG&E to ensure its BMI addresses certain shortcomings and persistent 4 billing problems associated with its legacy billing system, including by:
5 o Sharing certain critical billing data with CCAs.
6 o Addressing various issues with the quality of the billing data currently 7 shared with the CCAs.
8 o Dedicating more resources toward resolving CCA customer billing issues 9 and delays in a timely manner, including via a designated PG&E point of 10 contact for such issues and a semi-annual PG&E-CCA stakeholder 11 workshop on resolving outstanding technical billing issues. 12 o Clarifying, via an advice letter filing, PG&E’s plan regarding how and when 13 it will communicate with various customer groups on major upcoming 14 changes arising out of the BMI, with the constraint that PG&E must provide 15 at least three months’ notice in advance of implementation of such billing 16 changes.
17 o Remediating various issues with billing mechanics and delays related to rate 18 switch requests, inaccurate applications of bill credits, and backlogged 19 billing projects.
20 • Order PG&E to regularly track and publicly report on its billing system efficiency 21 metrics, and ensure that its BMI allows it to achieve consistent quarterly 22 improvements on these efficiency metrics;
23 • With respect to the rollout of the BMI, order PG&E to: (1) commit to specific dates 24 certain for achieving implementation of its backlogged rate projects, and (2) 25 commit to a specific timeline of seven business days for resolving any CCA billing 26 and revenue delays arising out of the BMI deployment; and 27 • Order PG&E to clearly outline the BMI’s likely impact on CCA service fees and 28 commit to service fee updates post BMI implementation. 11 1 II. THE COMMISSION SHOULD ORDER PG&E TO IMPLEMENT SPECIFIC 2 CHANGES RELATED TO THE PRESENTATION OF ITS CUSTOMER BILLS 3 DURING THE BMI PROCESS.
4 Q: Why do PG&E’s choices regarding bill presentation matter to the Joint CCAs? A: PG&E is the statutorily designated billing agent for the CCAs in its service territory. 5 6 As
6 the designated billing agent, PG&E generates and issues bills for both its bundled and 7 unbundled electric customers, including customers of CCAs. PG&E also collects customer 8 bill payments on behalf of CCAs and transfers those payments to the CCAs. Because 9 PG&E controls the issuance of bills sent to CCA customers, CCAs cannot make changes 10 to much of the CCA-specific content on bills directly without first going through PG&E. 11 CCAs must ensure that the bills PG&E issues CCA customers contain accurate and 12 fair representations of their rates and other key customer-facing information. Additionally, 13 CCAs have an interest in ensuring clarity and transparency in both unbundled and bundled 14 customer bills, and specifically, in ensuring PG&E’s bundled customer bills do not 15 obfuscate or misrepresent the rate differences between bundled and unbundled service. 16 CCAs have been working on these issues since the inception of community choice 17 aggregation in California. Lastly, CCAs compete with PG&E for electric customers, so any 18 misrepresentation of rates or information on customer bills can impact a customer’s 19 understanding of their bill and potentially their decision to switch electric service providers. 20 Q: Does the Commission impose any standards on PG&E that apply to PG&E’s 21 approach to bill presentation?
22 A: Yes. The Commission’s Code of Conduct governing the conduct of investor-owned 23 utilities (IOUs) in their interactions with and treatment of CCAs applies to issues of bill 24 presentation. The Code of Conduct was adopted to ensure CCAs are able to “compete on 25 a fair and equal basis with other [load serving entities], and to prevent utilities from using their position or market power to gain unfair advantages.”7 26 The Code of Conduct provides, 6 Cal. Pub. Util. Code § 366.2(c)(9).
7 D.12-12-036, Finding of Fact (FOF) 4 (definition added). 12 1 among other things, that PG&E may not, “through a tariff provision or otherwise, discriminate between its own customers and those of a CCA.”8 2 3 Q: Why are the Joint CCAs concerned with bill presentment in this proceeding in 4 particular?
5 A: The upgrades to PG&E’s billing system through the BMI will have an impact on customer 6 bill format and presentation. However, at this phase in the BMI process, PG&E is unable 7 to confirm what specific changes in bill presentment will look like for bundled versus CCA 8 customers. Possible changes to bill presentment will not be known for several years until Stage 3 of the BMI process, according to PG&E.9 9
10 Scoping Issue 6 from the Scoping Ruling specifically addresses whether the BMI 11 upgrades will support corrections to the current bill presentation to facilitate greater 12 transparency and foster fair competition. Leaving modifications to bill presentation to 13 PG&E’s discretion at a later phase of the upgrade process is not reasonable. This approach 14 would give PG&E the green light to continue certain anticompetitive billing practices related to how it presents bundled and unbundled customer rates and charges differently,10 15 16 and would give PG&E the option to disregard specific CCA concerns regarding their ability 17 to present clear messaging on their customers’ bills and update that content in a timely 18 manner. I believe it is important to approach the BMI bill redesign process with the goal 19 of addressing the needs of both unbundled and bundled customers simultaneously—this 20 approach ensures that the needs of CCA customers are not considered an afterthought and 21 protects against anticompetitive outcomes.
22 Q: What bill presentment issues do you discuss in this section of your testimony? 23 A: I discuss the following bill presentment recommendations in this section of my testimony:
24 • The Commission should order PG&E to (1) adopt certain bill presentation changes to 25 facilitate CCA communication with their customers, and (2) conduct joint PG&E-CCA 8 D.12-12-036, Attachment 1: Code of Conduct and Expedited Complaint Procedure, Rules 14 and

18. 9
Attachment KJC-2 (PG&E Response to PCE DR 1.10).
10 Specifically, I am referring here to the presentation of CARE and FERA discounts as well as the PCIA charge on customer bills, discussed further in Section II herein. 13 1 stakeholder workshops on comprehensive bill redesign and the implementation of CCA 2 bill presentation changes prior to the design portion of Phase 3. 3 • The Commission should order PG&E to develop its dynamic rate presentation 4 approach collaboratively with CCAs through the joint PG&E-CCA stakeholder 5 workshops prior to the design portion of Phase 3 or the implementation of dynamic 6 rates.
7 • The CARE and FERA discounts should be reflected on both unbundled and bundled 8 customers’ bills by Q3 of 2026.
9 • The PCIA should be reflected on both unbundled and bundled customers’ bills by Q3 10 of 2026.
11 A. PG&E Should Adopt Bill Presentation Changes to Facilitate Communications 12 Between CCAs and Their Customers.
13 Q: Please explain the relationship between customer bills and communication between 14 customers and their CCA.
15 A: Monthly bills are one of the primary means by which customers access information about 16 their electric rates. As such, CCAs often use monthly bills to communicate important 17 information to customers, including key contact information, rate updates, and general 18 information about CCA service.
19 Q: Why are the CCAs concerned with customer messaging issues on unbundled 20 customer bills?
21 A: The Joint CCAs are concerned with both PG&E’s lengthy turnaround times for 22 implementing messaging changes and particular areas of inflexibility. The billing agent relationship between PG&E and CCAs is mandated by law,11 23 and pursuant to that 24 relationship, PG&E manages the process for implementing most customer messaging on 25 CCA customer bills. The ability to provide accurate and detailed information to customers 26 in conjunction with rates and charges is critical for ensuring transparency, especially 27 because a monthly bill typically represents a customer’s most frequent interaction with its 28 electric service provider. Constraints to a CCA’s ability to communicate with its customers 11 Cal. Pub. Util. Code § 366.2(c)(9).
14 1 through bills unnecessarily harms the CCA’s relationship with its customers. Certain issues 2 surrounding messaging constraints also create a competitive disadvantage for CCA 3 providers, as discussed in more depth below.
4 Q: How does PG&E currently reflect CCA customer messaging on customer bills? 5 A: An unbundled customer bill issued by PG&E contains areas where messaging can be 6 included to allow a CCA to communicate information to its customers. Typically, there are 7 two areas where a CCA can include messaging on a customer bill: the “swim lane” and the 8 “on-bill message.” The on-bill message area is more limited in size compared to the swim 9 lane and appears under the CCA’s generation charges section of an unbundled customer’s 10 bill.
11 Q: Can you provide an example of what this looks like on a typical CCA customer bill? 12 A: Yes. Figure 1 below is an example of an unbundled customer bill showing where CCA-13 specific customer messaging can occur. The red box on the left is the on-bill message, 14 while the red box on the right is the swim lane.
15 15
Figure 1: CCA Customer Messaging Options on PG&E Bills12 1 Q: What is PG&E’s current process for facilitating updates to this customer messaging 2 on CCA customer bills?
3 A: PG&E handles CCAs’ requests for updates to the swim lane portion of the bill, and it does 4 not utilize a standard or formalized form or timeline for implementing these changes. For 5 on-bill messaging, a CCA currently can update or change this messaging as needed through 6 their back-office billing provider. CCAs want to maintain this level of control over on-bill 7 messaging even after the BMI upgrades are complete.
8 PG&E’s current timeline to implement a CCA request to update “swim lane” 9 language is typically two to three months, depending on internal review, legal compliance 12 Attachment KJC-2 (PG&E Response to PCE DR 2.15).
16 changes, and scheduling of IT development work.13 1 As PG&E has stated, this is the typical timeline for processing changes, but the processing timeline can vary.14 2 3 Q: What issues do the Joint CCAs have with the current process of updating customer 4 messaging on CCA customer bills?
5 A: PG&E’s timeline to implement a request to change CCA-specific messaging on the swim 6 lane portion of the bill is too lengthy. A typical timeline of two to three months for a change in messaging15 7 could easily render a requested message change invalid by the time it is 8 included on the customer’s bill, especially if it is time-sensitive messaging. PG&E 9 recognizes that other IOUs may have different timelines, and that SCE processes on-bill messaging requests from CCAs within only two business days.16 10 However, PG&E claims 11 that differences in system architecture, configurations and integrations, and processes account for these timeline differences.17 12 PG&E maintains that it cannot comment on system 13 capabilities that may support improved message configuration and scheduling until Stage 14 3 of the BMI and it does not expect immediate changes to the processing timeline until those future-stage functionalities are incorporated.18 15 16 Q: Do the Joint CCAs have other concerns surrounding PG&E’s process for updating 17 CCA customer messaging?
18 A: Under the current process, PG&E must approve of the language to be included in the swim 19 lane before the update goes live on a CCA customer’s bill. However, CCAs are not allowed 20 to review or approve PG&E’s final messaging in the swim lane prior to its implementation. 21 This dynamic is anti-competitive, allowing PG&E final discretion as to the ultimate 22 message conveyed to CCA customers.
13 Attachment KJC-2 (PG&E Response to PCE DR 2.14).
14 Id.
15 Id.
16 Attachment KJC-2 (PG&E Response to PCE DR 2.14); see also Attachment KJC-3 (SCE Bill Message Request Template).
17 Attachment KJC-2 (PG&E Response to PCE DR 2.14).
18 Id.
17 1 Q: What other concerns do the Joint CCAs have with PG&E’s current on-bill messaging 2 capabilities?
3 A: Based on my conversations with CCA representatives, PG&E unreasonably constrains 4 CCAs’ ability to efficiently and effectively communicate with their customers via 5 messaging on customer bills. First, I understand that PG&E provides CCAs with little 6 flexibility and text space for messaging in both the “swim lane” portion of the bill and the 7 “on-bill message” portion of the bill. For example, PG&E will not reorder the swim lane 8 or allow placement of the requested messaging in a manner that moves the “about” 9 information from the bottom right corner. Further, PG&E will not incorporate clickable URLs in online bills, CCA logos in color, or messaging in color.19 10 Finally, CCAs are unable 11 to incorporate customer-specific messaging on customer bills, e.g., messaging specific to 12 CARE, FERA, or EV customers. CCAs similarly are unable to differentiate messaging by 13 customer class, e.g., residential or commercial.
14 Q: What are your specific recommendations for improving PG&E’s approach to CCA 15 customer messaging on bills?
16 A: As part of the BMI, the Commission should require PG&E to make the following changes 17 to its CCA customer messaging capabilities and approach:
18 • Shorten the timeline it takes to process CCAs’ requested changes to the swim lane portion of the bill to be in line with SCE’s timeline of two business days.20 19 20 • Design the BMI system to have increased flexibility and text space for messaging (in 21 both the swim lane and on-bill message).
22 • Limit the ability of PG&E to modify requested CCA specific messaging and require 23 PG&E to provide the final version of the modified language to CCAs for final signoff. 24 • Design the end-state billing system to allow placement changes of the CCA messaging 25 (i.e., allow the “about” information to be moved from the bottom right corner). 26 • Design the end-state billing system to allow CCAs to incorporate customer-specific 27 messaging on customer bills (e.g., messaging specific to particular customer classes, to 19 Attachment KJC-2 (PG&E Response to PCE DR 2.16).
20 See Attachment KJC-3 (SCE Bill Message Request Template). 18 1 customers who are enrolled in specific programs like CARE or FERA, and to EV 2 customers).
3 • Design the end-state billing system to allow clickable URLs in online bills, CCA logos 4 in color, and messaging in color.
5 Q: Do you have any other recommendations regarding CCA customer bill presentation? 6 A: Yes. PG&E has indicated that it is not yet in the phase of the BMI where it can work on 7 bill presentment and is unable to answer questions regarding proposed changes to bill presentment.21 8 In light of PG&E’s inability to work on comprehensive bill redesign at this 9 time, the Commission should order PG&E to conduct joint PG&E-CCA stakeholder 10 workshops on comprehensive redesign of customer bills prior to the design portion of BMI 11 Phase 3.
12 This workshop series should cover a holistic review of PG&E’s bill design, with 13 the goal of redesigning bills to be clear and easily understandable to both unbundled and 14 bundled customers. Bills must be designed with the understanding that unbundled 15 customers represent the majority of PG&E’s customers, and that therefore bills should be 16 designed with CCA customer needs in mind and in conjunction with CCA representatives. 17 Finally, if needed, this workshop series could also cover any lingering issues with the 18 implementation of the specific CCA bill presentation changes recommended herein. 19 B. PG&E Should Develop Dynamic Rate Presentation Collaboratively with CCAs 20 Through a Workshop Process.
21 Q: What are dynamic rates?
22 A: Dynamic rates are rates that vary by time and that are structured to provide incentives to 23 customers to conserve electricity when demand is low through differences in rates. 24 Whereas time-of-use rates are set by time of day and remain in place throughout the season, 25 dynamic rates change from day to day and hour to hour. This means that dynamic rates 26 provide a more granular and variable price signal about when to shift load compared to time-varying rates.22 27
21 Attachment KJC-2 (PG&E Response to PCE DR 1.10).
22 D.21-12-015, p. 85.
19 1 In D.21-12-015, several dynamic rate program pilots were approved by the Commission for PG&E and SCE.23 2 In particular, PG&E was instructed to work with Valley 3 Clean Energy, a CCA in PG&E’s service territory, on funding, administration, tariff design, 4 and evaluation for a pilot program where dynamic rates would be used to provide incentives for large agricultural customers to pump water when it is least costly to do so.24 5 6 This pilot program, as well as SCE’s program approved in D.21-12-015, were both expanded in D.24-01-032, issued on January 25, 2024.25 7 These two programs were authorized to run from 2024 to 2027.26 8
9 Additionally, in October 2022, the California Energy Commission adopted updated 10 state load management standards, effective April 1, 2023, that required PG&E, SCE, the 11 Sacramento Municipal Utility District (SMUD), San Diego Gas and Electric Company 12 (SDG&E), Los Angeles Department of Water and Power (LADWP), and large CCAs to develop retail electricity rates that change at least hourly.27 13 In particular, large CCAs were 14 required, if approved by their rate approving bodies, to either adopt the dynamic price rate 15 design required of IOUs, develop their own dynamic rates, or provide load shifting programs to customers by 2027.28 16 The advent of dynamic rates has clearly impacted both 17 the California IOUs and CCAs and therefore the implementation of dynamic rates through 18 the BMI is of particular interest to CCAs.
19 Q: How will dynamic rates on customer bills be handled under PG&E’s BMI? 20 A: PG&E explains that final bill presentment features, which include the display of dynamic 21 rate components, have not yet been finalized and are not expected to be incorporated until 22 Stage 3 of the BMI. At this time, PG&E states it is unable to confirm the final format or 23 level of detail for dynamic rates that will be presented on customer bills. PG&E expects 23 Id., p. 89 and p. 96.
24 Id., p. 87 and p. 89.
25 D.24-01-032, pp. 2-3.
26 Id., p. 2.
27 CEC 2022 Load Management Standards Rulemaking Fact Sheet, available at https://www.energy.ca.gov/sites/default/files/2022-10/Load_Management_Fact_Sheet_ADA.pdf. 28 See LMS § 1623.1(b).
20 1 that decisions impacting the presentation of dynamic rates will be determined later in the program based on system capabilities, customer needs, and regulatory guidance.29 2 3 Q: How should PG&E determine how to present dynamic rates on customer bills in 4 PG&E’s upgraded billing system?
5 A: As dynamic rates are not currently in place for all customers and it is unclear at this time 6 how these may be reflected on customer bills, the Commission should order PG&E to 7 address this issue in the joint PG&E-CCA workshop series recommended above, prior to 8 the design portion of BMI Phase 3. CCAs must be equal partners in determining dynamic 9 rate bill presentation because this will help ensure that both bundled and unbundled 10 customers are treated consistently when it comes to the presentation of dynamic rates on 11 bills. Overall, this will maintain consistency and improve transparency for customers when 12 reviewing their bills.
13 C. CARE And FERA Discounts Should Be Clearly Reflected on Both Bundled and 14 Unbundled Customer Bills by Q3 of 2026.
15 Q: What are the CARE and FERA discounts?
16 A: The CARE program offers a 30-35% or more discount on electric bills for customers with 17 a household income under 200% of Federal Poverty Guidelines, or customers enrolled in certain other public assistance programs.30 18 The FERA program offers an 18% discount on electric bills if a customer’s household income slightly exceeds CARE allowances.31 19 Both 20 bundled and unbundled customers may be eligible to receive CARE and FERA discounts, 21 and these discounts apply to the customer’s entire bill. 22 Q: Are CARE and FERA discounts currently reflected clearly on PG&E customer bills? 23 A: Partially. On the first page of customer bills for bundled and unbundled customers, PG&E 24 identifies the CARE or FERA discounts clearly and consistently. Figure 2 below reflects 25 the “Account Summary” section of both types of customer bills, which identifies the 29 Attachment KJC-2 (PG&E Response to PCE DR 2.17).
30 “California Alternative Rates for Energy (CARE),” available at https://www.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/california-alternate-rates-for-energy. 31 “Family Electric Rate Assistance Program (FERA),” available at https://www.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/family-electric-rate-assistance-program. 21 1 program the customer is enrolled in as well as the total amount of credit included on the 2 customer’s bill.

Figure 2: Account Summary Section of PG&E Electric Bill for Bundled and Unbundled Customers32
32 Attachment KJC-2 (PG&E Response to PCE DR 2.18).
22 1 Q: Beyond the “Account Summary” section, are the CARE and FERA discounts 2 presented consistently on the remainder of bundled and unbundled customer bills? 3 A: No. Contrary to PG&E’s assertion otherwise, it does not present CARE and FERA discounts in a consistent manner between bundled and unbundled customers.33 4 5 Q: Can you provide an example of how CARE and FERA discounts are presented on a 6 typical unbundled customer bill?
7 A: Yes. For unbundled customers, the CARE or FERA credit shows up as a discount line-item 8 in the “Details of PG&E Electric Delivery Charges” section of a customer’s bill, as shown 9 in Figure 3 below. This section of an unbundled customer’s bill details the PG&E electric 10 delivery charges, but not always the customer’s electric generation charges.

Figure 3: CARE and FERA Discounts on PG&E Unbundled Customer Bill34 33 Attachment KJC-2 (PG&E Response to PCE DR 2.18c).
34 Attachment KJC-2 (PG&E Response to PCE DR 2.18).
23 1 Q: Can you provide an example of how CARE and FERA discounts are presented on a 2 typical bundled customer bill?
3 A: For bundled customers, the CARE and FERA discount shows up as a discount to the “Total 4 Electric Charges” section of a bundled customer’s bill. This section of a bundled 5 customer’s bill reflects charges for both electric delivery and generation. This is reflected 6 in Figure 4, below.

Figure 4: CARE and FERA Discount on PG&E Bundled Customer Bill35 7 Q: On first glance, these discounts appear to be displayed similarly. Can you please 8 explain the discrepancies between the CARE and FERA bill presentation on bundled 9 and unbundled bills?
10 A: CARE and FERA discounts apply to both delivery and generation services. PG&E clearly 11 communicates this fact through bundled customer bills by including the CARE or FERA 12 discount within the “Total Electric Charges.” Conversely, for unbundled customers, PG&E 13 reflects the CARE or FERA discount as a reduction solely to PG&E’s delivery service. 14 The current presentation of CARE and FERA discounts on unbundled customer 15 bills is confusing in that it appears these discounts are not applicable to CCA generation 16 charges. In other words, it appears that unbundled customers receive only a portion of the 17 CARE or FERA discount, as opposed to bundled customers whose entire bill is discounted. 35 Id.
24 1 Q: What are your concerns with this confusing bill presentation? 2 A: Clear bill presentation is key in ensuring that customers fully understand the rates they pay. 3 While PG&E does include a clear mention of the applicable CARE or FERA discount in 4 the “Account Summary” section, this description alone is not sufficient. It is also necessary 5 that these discounts be presented clearly where all other electric charges and discounts are 6 laid out, which is likely the first place customers will look to understand their monthly bill. 7 Beyond customer confusion, current CARE and FERA bill presentation could also 8 create anticompetitive effects. For example, unbundled customers may opt to return to 9 bundled PG&E service under the mistaken belief that they will once again receive the full 10 CARE or FERA discount after returning to bundled service. 11 Q: What changes are you recommending regarding how CARE and FERA discounts are 12 presented on bundled and unbundled customer bills?
13 A: I recommend that the Commission require PG&E to reflect all discounts that are calculated 14 based on the total bill, such as the CARE and FERA discounts, in a completely consistent 15 manner and as a reduction to an eligible customer’s total electric charges, with no 16 differences between a bill for bundled customers versus unbundled customers. For 17 unbundled customers, these discounts should not be shown as a reduction to only the 18 delivery charges portion of unbundled customers’ bills. The specific changes for how this 19 should be reflected on bundled and unbundled customer bills can be determined through 20 my recommended workshops between PG&E and the CCAs.
21 Q: By what deadline should the Commission order PG&E to implement these changes? 22 A: PG&E explained that it is too early to confirm what changes, if any, will be made to the 23 presentation of CARE and FERA discounts or how these changes may differ between 24 bundled and unbundled customers. PG&E states it will not have any clarity on these potential changes until Stage 3 of the BMI.36 25 It is unreasonable to allow PG&E to continue 26 with its massive BMI investment without any guarantee as to whether or at what time the 27 upgrades will facilitate improved CARE and FERA bill presentation. Accordingly, the 28 Commission should order PG&E to conduct joint PG&E-CCA stakeholder workshops and 36 Attachment KJC-2 (PG&E Response to PCE DR 1.11).
25 1 to implement the recommendations regarding total bill discounts by no later than Q3 of 2 2026, when PG&E implements the second stage of the BMI process, CC&B 25.1. 3 According to PG&E, the implementation of the update to CC&B 25.1 is scheduled to go live in Q3 of 2026.37 4
5 D. The PCIA Should Be Broken Out as a Line Item on Bundled Customer Bills by 6 Q3 of 2026.
7 Q: What is the PCIA?
8 A: Bundled and unbundled customers alike are responsible for paying the above-market costs 9 of PG&E’s generation resources procured on their behalf. These costs are reflected in the 10 PCIA. PG&E develops PCIA rates in its annual Energy Resource Recovery Account 11 (ERRA) Forecast proceedings to determine all customers’ responsibility for these above-12 market costs. Unbundled customers are subject to a separate, non-bypassable PCIA charge 13 to cover their share of the above-market generation costs. PG&E currently recovers 14 bundled customers’ share of PCIA costs through its Bundled PCIA tariff rates. 15 Q: Before discussing the challenges surrounding the current PCIA bill presentation, has 16 the Commission provided any specific direction to PG&E on this topic? 17 A: Yes. Per Resolution E-5131, adopted by the Commission in 2021, PG&E was required to 18 add the PCIA to bundled customer bills by December 31, 2021. However, compliance with 19 this order has been delayed due to PG&E’s billing infrastructure upgrades. 20 Q: How does PG&E currently present the PCIA charge on unbundled customer bills? 21 A: Unbundled customer bills currently show a customer’s PCIA charge as a single line item 22 on their bill located on the “Details of PG&E Electric Delivery Charges” page of the bill. 23 While the PCIA is broken out from other electric generation charges, it does not include 24 the sum of the kWh quantity used nor the applicable $/kWh PCIA rate, only the vintage of the PCIA.38 25
37 Application, p. 8.
38 Attachment KJC-2 (PG&E Response to PCE DR 2.13).
26 1 Q: How does PG&E currently present the PCIA charge on bundled customer bills? 2 A: In contrast to unbundled customer bills, PG&E does not display the PCIA rate as a separate 3 line item on bundled customers’ bills. Instead, it is only found in the specific rate tariff under a section entitled “UNBUNDLING OF TOTAL RATES.”39 4 5 Q: Can you give an example of how a typical unbundled customer bill versus a typical 6 bundled customer bill looks in this regard?
7 A: Yes. PG&E provided samples of current bundled and unbundled customer bills in response 8 to a data request from PCE. Those samples are reflected in Figure 5 below. 39 Id.
27 Figure 5: Comparison of PG&E Electric Generation Charges Section from Current Unbundled and Bundled Customer Bills40
40 Id.
28 1 Q: What are some of the issues with current PCIA bill presentation on unbundled 2 customer bills?
3 A: As shown in Figure 5: Comparison of PG&E Electric Generation Charges Section 4 from Current Unbundled and Bundled Customer Bills5, the PCIA for unbundled 5 customers is displayed as a single charge on the unbundled customer’s bill in the “Details 6 of PG&E Electric Delivery Charges” section. The PCIA line item does not display the 7 relevant kWh usage or $/kWh rate applied. Without this information presented clearly on 8 monthly bills, unbundled customers have no readily available way to understand that the 9 PCIA is a volumetric charge, or how it is calculated. 10 The only other information regarding the PCIA within this section of the bill is 11 similarly confusing. Under the total delivery charges in Figure 5 for unbundled customers, 12 there is a line item that reads “2016 Vintage Power Charge Indifference Adjustment” with 13 no clear indication what this applies to. Without additional context, most customers likely 14 do not understand what their PCIA vintage is, how it was assigned, and most importantly, 15 how it impacts their rates.
16 Q: What are some of the issues with current PCIA presentation on bundled customer 17 bills?
18 A: Although bundled customers pay the latest vintage of the PCIA every year, the PCIA 19 charge is not specifically identified as a charge on bundled customers’ bills. As 20 demonstrated in Figure 5, bundled customers’ PCIA charges are not included as a specific 21 line-item charge as on unbundled customer bills. Rather, PG&E simply includes a sidenote 22 that “a portion of your (bundled) electric charges currently includes the Power Charge Indifference Adjustment (PCIA).”41 23
24 Q: What are the consequences of both the general opacity and discrepancies in PCIA bill 25 presentation between bundled and unbundled customers? 26 A: Presenting the PCIA charge as a line item solely for unbundled customers creates a visual 27 misrepresentation that only unbundled customers are subject to this charge. This is 28 compounded by the fact that the PCIA charge for unbundled customers is not displayed as 41 Id.
29 1 volumetric—instead, it appears to simply be a monthly charge associated with CCA 2 service.
3 In a similar vein, embedding PCIA charges in bundled customer commodity rates 4 masks bundled customers’ responsibility for these costs, thereby reducing customers’ 5 understanding of their rates. While PG&E explains that bundled customers pay the PCIA 6 in separate sections of the bill, the absence of the actual PCIA charge within bundled 7 customers’ electric generation charges could easily be misconstrued by any customer that 8 bundled customers do not pay a PCIA charge as part of their electric charges. 9 Opaque billing practices such as these can make it impossible for both bundled and 10 unbundled customers to accurately compare the costs and benefits of selecting a load-11 serving entity (LSE) between PG&E, CCAs, or Direct Access (DA) providers. This 12 dynamic creates a distinct competitive disadvantage for alternative LSEs, such as CCAs, 13 by implying that the PCIA rate is an “additional” charge specific to unbundled service 14 instead of a rate paid by both bundled and unbundled customers. 15 Q: Have the CCAs worked to address this disparity between bundled and unbundled 16 customer bills in other proceedings?
17 A: Yes. The CCAs have been actively involved in several proceedings in front of the 18 Commission to address this disparity, and this topic remains of top interest to the CCAs. 19 With regard to PG&E’s PCIA bill presentation specifically, several of the Joint CCAs participated in PG&E’s 2020 Phase 2 General Rate Case (GRC),42 20 where the 21 Commission approved several rate design settlements that resulted in the separation of 22 PG&E’s PCIA rates from bundled customer generation rates in the context of designing generation rates and publishing tariff schedules.43 23 Separating the PCIA in bundled tariff 24 rates was intended as a necessary first step to allow PG&E to move forward with more 25 transparent PCIA bill presentment.
42 A.19-11-019.
43 D.21-11-016, pp. 84, 140, and 149-152 (PCE, MCE, Ava (formerly East Bay Community Energy), SJCE, SVCE and SCP participated in PG&E’s GRC Phase II). 30 1 Q: Has the Commission issued any other guidance relevant to this issue? 2 A: Yes. The Commission has repeatedly stressed the importance of transparency in bill 3 presentation and ensuring competitive neutrality between CCAs and IOUs, both within the 4 billing context generally and specifically with regard to PCIA bill presentation. For 5 example:
6 • D.22-05-015: “It is important to have transparency of costs in bill presentation, as much 7 as possible, so customers can more effectively compare costs related to generation and distribution services, and to promote fair competition among retail providers.”44 8 9 • D.18-10-019: “We agree that bundled customers should be made aware of the fact that 10 all customers are paying their share of the utility’s uneconomic costs. Clearly, changes to bills are necessary.”45 11
12 • Resolution E-4734: “Breaking out the PCIA as a separate change on a customer’s bill 13 is not precluded by the Decision either. We are persuaded by MCE and CCSF that 14 ensuring that bill comparisons are equivalent between CCA and GTSR customers are 15 reasonable and in accord with general state policy to maintain competitive neutrality 16 between CCAs and IOUs…we order SCE and PG&E in their supplements to the 17 CSIALs, and in their implementation of the GTSR program, to break out, for PG&E, 18 the PCIA…as a separate charge on a GTSR customer’s bill and to ensure that the bill describes the PCIA…in a way that is easily understandable.”46 19 20 Q: To ensure transparency and competitive neutrality, how should the PCIA charge be 21 presented on all customer bills?
22 A: To increase rate transparency, ensure consistency, and allow customers to make fair 23 comparisons between the unbundled and bundled rates they are charged, the PCIA charge 24 on all customer bills should also be displayed as separate line item, depicting the kWh 25 quantity and kWh rate, which mathematically results in the total PCIA charge included in 26 a customer’s bill.
44 D.22-05-015, FOF 17.
45 D.18-10-019, p. 119.
46 Resolution E-4734, pp. 11-12 (Oct. 2, 2015).
31 1 Q: Has PG&E provided any information as to the timing of Commission-ordered 2 updates, or whether the BMI will facilitate greater PCIA transparency on customer 3 bills?
4 A: PG&E originally planned to implement a breakout of the PCIA charge (kWh quantity and 5 kWh rate) on bundled customers’ billing statements, but this implementation was delayed until the end of 2027 due to the BMI process.47 6 At this time, PG&E will not confirm if and 7 how the presentation of the PCIA will change under the new billing system. Additionally, 8 PG&E states it is unable to confirm whether customer bills for either bundled or unbundled 9 customers will display both the kWh usages and applicable kWh rate used to calculate the 10 monthly PCIA charge. PG&E explained that it will not know the details of bill presentment for the PCIA charge until Stage 3 of the BMI.48 11
12 Q: Is it reasonable for the Commission to allow PG&E an unbounded extension to break 13 out the PCIA and discretion as to whether it should implement updates for 14 transparency?
15 A: No. Given the Commission’s outstanding order that PG&E implement changes to PCIA 16 bill presentation, as well as the history of clear Commission guidance regarding the 17 importance of bill transparency, the Commission should set a definitive timeline by which 18 PG&E should implement the recommendations described herein. Specifically, the 19 Commission should require PG&E to implement these PCIA billing presentment updates 20 no later than Q3 of 2026, when PG&E implements the second stage of the BMI process, 21 CC&B 25.1. According to PG&E, the implementation of the update to CC&B 25.1 is scheduled to go live in Q3 of 2026,49 22 which is more than 10 years later than the Commission 23 order which required PG&E to separate the PCIA charge for bundled customers and ensure the bill describes the PCIA in a way that is easily understandable.50 24 47 Attachment KJC-2 (PG&E Response to PCE DR 1.13).
48 Attachment KJC-2 (PG&E Response to PCE DR 1.10).
49 Application, p. 8.
50 Resolution E-4734, pp. 11-12 (Oct. 2, 2015).
32 1 III. THE COMMISSION SHOULD NOT ALLOW PG&E TO FUNCTIONALIZE ANY 2 BMI COSTS TO THE ELECTRIC GENERATION FUNCTION.
3 Q: Please summarize this section of your testimony.
4 A: In this section of my testimony, I will address the issues with PG&E’s proposal to allocate 5 BMI costs using a modified version of the common cost allocation methodology as defined 6 by D.23-11-069 and D.24-12-038. Under PG&E’s application of this methodology, a 7 portion of BMI costs would be functionalized as electric generation, which I believe is 8 incorrect. Since the BMI takes end meter data and builds from these data sets, there are no 9 aspects of the BMI that can be directly tied to electric generation. Therefore, any BMI costs 10 PG&E currently plans to functionalize to electric generation should instead be added to the 11 BMI costs functionalized as distribution costs.
12 Q: Please explain the origins of the common cost allocation methodology. 13 A: In D.23-11-069, the Commission adopted a methodology for allocating particular costs 14 included in PG&E’s GRC that were classified as Common, General, and Intangible (CGI) 15 to different functional areas within PG&E. According to D.23-11-069, a portion of the 16 GRC CGI costs is allocated to PG&E’s generation function. These generation-related GRC 17 costs are then recovered from bundled and unbundled customers through PG&E’s 18 generation and PCIA rates. In PG&E’s annual ERRA Forecast proceedings, the generation-19 related GRC costs, including common costs, are apportioned among PG&E’s Portfolio 20 Allocation Balancing Account (PABA), ERRA, and New System Generation Balancing 21 Account (NSGBA) cost recovery mechanisms.
22 At the conclusion of PG&E’s 2025 ERRA Forecast proceeding, D.24-12-038 23 adopted a refined process for allocating the generation-related common costs approved in 24 the GRC. This updated approach allows PG&E to recover, among other things, Energy 33 1 Supply Administration (ESA) costs associated with PG&E generation procurement that are deemed common to both bundled and unbundled customers.51 2 3 Q: Please explain how PG&E proposes to apply the common cost allocation methodology 4 to BMI costs.
5 A: Using the GRC common cost allocation methodology, PG&E proposes to allocate BMI 6 costs totaling $393.1 million (2023-2030) to electric generation, electric distribution, gas distribution, gas transmission and storage, and gas local transmission functional areas.52 7 8 PG&E proposes that the BMI costs allocated to electric generation be allocated between 9 the ERRA, PABA, and NSGBA, with CCA customers sharing the costs allocated to PABA and NSGBA.53 10 More specifically, the BMI costs allocated to the PABA will be allocated 11 with other generation-related GRC costs to PCIA vintages UOG Legacy, 2009, 2010, 2011, and 2012.54 12
13 PG&E proposes to allocate a total of $40.5 million of BMI costs between 2023- 14 2030 to electric generation. Table 1 below shows the BMI costs PG&E proposes to allocate 15 to each functional area across the timeframe of the BMI.

Table 1: BMI Revenue Requirement Summary By Functional Area55 16 Q: Do you agree with the application of the common cost allocation methodology to BMI 17 costs?
18 A: I do not, because I do not agree with the allocation of any BMI costs to the electric 19 generation functional area. The goal of the BMI is to replace PG&E’s aging billing system 51 D.24-12-038, p. 30.
52 Attachment KJC-2 (PG&E Response to PCE DR 1.17).
53 Id. Note the electric generation functional area is the only revenue adjustment category under the common cost allocation methodology that distinguishes between bundled and CCA customers, and other types of departing load.
54 Id.
55 Id.

RRQ by Functional Area 2023 2024 2025 2026 2027 2028 2029 2030 2023-2030 Electric Distribution (ED) $344,930 $2,424,356 $7,886,196 $24,761,634 $33,598,519 $31,388,777 $26,905,630 $70,810,737 $198,120,780 Electric Generation (EG) $190,365 $1,337,992 $2,933,454 $4,755,492 $6,452,623 $6,028,240 $5,167,248 $13,599,260 $40,464,675 Gas Distribution (GD) $182,239 $1,280,877 $4,166,569 $13,082,488 $17,751,342 $16,583,853 $14,215,241 $37,411,934 $104,674,544 Gas Transmission & Storage (GT&S) $86,858 $610,482 $1,985,839 $6,235,278 $8,460,513 $7,904,073 $6,775,162 $17,830,998 $49,889,203 Total RRQ (without RF&U) $804,392 $5,653,707 $16,972,058 $48,834,893 $66,262,997 $61,904,944 $53,063,282 $139,652,929 $393,149,203 34 1 and move customers to “a single unified customer care, service order, metering, and billing system” that could deal with the complexities of the California energy market.56 2 None of 3 the BMI upgrades are related to, or caused by, anything concerning PG&E’s generation 4 business.
5 As the BMI costs are not at all related to the generation function, they should not 6 be functionalized as generation costs. It is inappropriate to recover non-generation costs 7 through an allocation methodology that includes generation. The purpose of 8 functionalization is to assign utility costs to the function they provide in the electricity supply chain.57 9 As the BMI costs relate to PG&E’s delivery services only, they should be 10 functionalized accordingly.
11 Q: Are BMI costs similar to the ESA costs to which PG&E applies the generation-related 12 common cost allocation methodology adopted by D.24-12-038 in PG&E’s ERRA 13 proceeding?
14 A: No. To my knowledge, the common costs at issue in D.24-12-038 are only related to 15 administering various aspects of PG&E’s generation business, not other functional areas 16 within PG&E. For example, in PG&E’s direct testimony in the 2025 ERRA forecast it 17 states, “The authorized ESA cost and the Forecast Collateral Costs … is the ‘Common Cost’ which PG&E is allocating.”58 18 ESA costs include the costs of business functions 19 performed by PG&E’s Energy Policy and Procurement organization, for example to 20 oversee and implement procurement-related activities such as bidding and scheduling generation into the CAISO market or administering new resource solicitations.59 21 Collateral 22 costs include carrying costs of posting collateral to counterparties to cover market movements associated with power supply related transactions.60 23 The costs included in the 24 BMI are to replace the utility’s aging billing system currently used to serve its electric and 56 PG&E Testimony, Chapter 1, p. 1-2.
57 National Association of Regulatory Utility Commissioners, Primer on Rate Design for Cost-Reflective Tariffs, p. 15 (Jan. 2021), available at https://pubs.naruc.org/pub.cfm?id=7BFEF211-155D-0A36-31AA-F629ECB940DC. 58 A.24-05-009, PG&E Prepared Testimony, p. 10-9.
59 A.24-05-009, PG&E Response to CalCCA Data Request 1.27. 60 A.24-05-009, PG&E Prepared Testimony, p. 6-6.
35 1 gas customers in the areas of billing, customer service, and customer data management and 2 do not have a direct connection to PG&E’s generation business. 3 Q: Did PG&E directly apply the common cost allocation methodology from D.23-11-069 4 to the costs in this case?
5 A: No, PG&E did not – it used a modified version of the methodology from D.23-11-069. As 6 stated previously, the Commission adopted a methodology for allocating particular costs 7 included in PG&E’s GRC that were classified as CGI to different functional areas using 8 the authorized Operations and Maintenance labor allocation factors adopted in D.23-11- 069.61 9 PG&E has recommended that all costs for the BMI project be allocated 100% to the 10 cost categories subject to the Commission’s jurisdiction, with no portion of the costs being 11 recovered from the cost categories under FERC jurisdiction even though PG&E references the use of the CGI allocation factors as adopted in D.23-11-069.62 12 The CGI allocation 13 methodology from D.23-11-069 includes an allocation to the FERC transmission function and this is shown in PG&E’s WP 7-1 CGI RRQ Allocation.63 14 Table 2 below shows 15 PG&E’s CGI estimated allocation factors by year and by function. 61 PG&E Testimony, Chapter 7, p. 7-7.
62 Id. at 7-7.
63 Attachment KJC-2 (PG&E Response to PCE DR 1.1, WP 7-1). 36 Table 2: CGI Allocation Factors by Functional Area by Year64 Functional
Area
Allocation %
2023 2024 2025 2026 2027 2028 2029 2030
Electric
Distribution
(ED) 38.772% 38.772% 41.679% 45.058% 45.058% 45.058% 45.058% 45.058% Electric
Generation
(EG) 21.398% 21.398% 15.504% 8.653% 8.653% 8.653% 8.653% 8.653% Gas
Distribution
(GD) 20.484% 20.484% 22.021% 23.806% 23.806% 23.806% 23.806% 23.806% Gas
Transmission
and Storage
(GT&S) 9.763% 9.763% 10.495% 11.346% 11.346% 11.346% 11.346% 11.346% Electric
Transmission
(ET) 9.583% 9.583% 10.302% 11.137% 11.137% 11.137% 11.137% 11.137% Total 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 1 In PG&E’s requested cost recovery, PG&E has taken the allocated percentage of 2 the CGI allocation factors for electric transmission and reallocated it to the electric 3 distribution, electric generation, gas distribution, and gas transmission and storage 4 functions. PG&E’s choice to modify the CGI allocation no longer aligns with the 5 Commission-approved allocation methodology PG&E claims that it used. Table 3 6 summarizes PG&E’s new CGI allocation factors, which have not been approved by this 7 Commission.
64 Id.
37 Table 3: PG&E’s Modified CGI Allocation Factors by Functional Area65 Functional
Area
Allocation %
2023 2024 2025 2026 2027 2028 2029 2030
Electric
Distribution
(ED) 42.881% 42.881% 46.466% 50.705% 50.705% 50.705% 50.705% 50.705% Electric
Generation
(EG) 23.666% 23.666% 17.284% 9.738% 9.738% 9.738% 9.738% 9.738% Gas
Distribution
(GD) 22.656% 22.656% 24.550% 26.789% 26.789% 26.789% 26.789% 26.789% Gas
Transmission
and Storage
(GT&S) 10.798% 10.798% 11.701% 12.768% 12.768% 12.768% 12.768% 12.768% Electric
Transmission
(ET) 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% Total 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 1 Q: Can you give examples of other, more appropriate approaches to allocating the costs 2 associated with upgrading or replacing a customer billing system used by an IOU? 3 A: Yes. One example is SCE’s functionalization of its recent billing systems upgrade entirely 4 to the electric distribution function. SCE submitted an application on July 22, 2021 (A.21- 5 07-009) for authorization to recover in rates the costs tracked in its Customer Service Re-6 Platform Memorandum Account (CSRPMA). The CSRPMA tracks costs associated with 7 SCE’s Customer Service Re-Platform (CSRP) project, which replaced SCE’s legacy 8 Customer Service System (CSS) in April of 2021 with a new enterprise customer 9 relationship and billing system to perform core customer service-related functions, such as 10 generating customer bills, processing payments, enabling customer account management, and providing customer access to SCE rates and programs.66 11 SCE’s requested cost recovery 65 Id. (percentage calculation of RRQ by Functional Area table). 66 D.23-03-019, p. 2.
38 1 mechanism—which was approved by the Commission in D.23-03-019—functionalized all CSRP costs to electric distribution.67 2
3 Another example is Duke Energy Ohio, Inc. (Duke). Duke submitted an application 4 to the Public Utilities Commission of Ohio in 2019 (Case No. 19-1750-EL-UNC) for 5 approval to include Duke’s Rider PF in its initial infrastructure modernization plan 6 consisting of customer information system upgrades and other infrastructure investment 7 programs (Infrastructure Modernization Plan) and for deferral authority for Operations and 8 Maintenance (O&M) costs, incremental to amounts in base electric and natural gas rates that have been or will be incurred in relation to the Infrastructure Modernization Plan.68 9 10 The Ohio Commission’s Finding and Order in that case determined “the revenue 11 requirement shall be allocated based on the percentage of base distribution revenues 12 approved in the Company’s most recent electric rate case. In Duke’s next electric rate case, 13 the Company’s application will include a proposal to roll plant-in-service assets, depreciation, and property taxes from Rider PF filings into base rates.”69 14 In other words, 15 the costs tied to system upgrades and investments associated with Duke’s Infrastructure 16 Modernization Plan were allocated solely to the utility’s distribution function, not its 17 electric generation function—unlike PG&E’s proposed approach to allocating BMI costs 18 here.
19 Q: How should PG&E treat the BMI costs it proposes to allocate to electric generation? 20 A: In this Application, PG&E is proposing a new CGI allocation methodology that is 21 inconsistent with the methodology that the Commission previously endorsed; this proposed 22 methodology should be rejected in this case. For all the reasons discussed herein, there 23 should be no costs allocated to the electric generation function, as the BMI costs are not 24 related to PG&E’s generation business. I recommend that PG&E instead follow SCE’s and 25 Duke’s example and re-allocate the BMI costs it currently proposes to functionalize as 67 Id., Ordering Paragraph (OP) 2.
68 Case No. 19-1750-EL-UNC, In the Matter of the Application of Duke Energy Ohio, Inc. for Authority to Adjust its Rider PF, Finding and Order, p. 1. 69 Id., p. 4.
39 1 electric generation costs to the electric distribution function to ensure all electric customers 2 are treated consistently in the recovery of the BMI costs. 3 Q: Can you summarize the impact of your proposal regarding cost functionalization on 4 PG&E’s revenue requirement request?
5 A: This proposal has no impact on the magnitude of PG&E’s revenue requirement request; it 6 only impacts how this revenue requirement would be functionalized. I have summarized 7 my proposed changes in Table 4 below.

Table 4: Joint CCAs’ Proposed BMI Revenue Requirement
Summary by Functional Area
8 Q: Why is it important that none of the BMI costs be allocated to the generation 9 function?
10 A: This is important for a few reasons. First, as noted above, the purpose of functionalization 11 is to assign utility costs to the function those costs serve in the electricity supply chain. 12 PG&E’s cost functionalization proposal does not accurately do this, and it should be 13 modified so that it aligns with this generally accepted best practice in ratemaking— 14 especially since the methodology PG&E proposes is not consistent with the CGI allocation 15 methodology previously approved by this Commission.
16 Second, this issue matters to CCA customers in particular because recovery of BMI 17 costs through the PABA will raise PCIA rates—a line item on unbundled customer bills 18 that makes unbundled service appear more expensive. The Commission should not allow RRQ by Functional Area 2023 2024 2025 2026 2027 2028 2029 2030 2023-2030 Electric Distribution (ED) $535,295 $3,762,348 $10,819,650 $29,517,126 $40,051,142 $37,417,017 $32,072,878 $84,409,997 $238,585,455 Gas Distribution (GD) $182,239 $1,280,877 $4,166,569 $13,082,488 $17,751,342 $16,583,853 $14,215,241 $37,411,934 $104,674,544 Gas Transmission & Storage (GT&S) $86,858 $610,482 $1,985,839 $6,235,278 $8,460,513 $7,904,073 $6,775,162 $17,830,998 $49,889,203 Total RRQ (without RF&U) $804,392 $5,653,707 $16,972,058 $48,834,893 $66,262,997 $61,904,944 $53,063,282 $139,652,929 $393,149,203 40 1 PG&E to funnel costs through the PCIA that improperly inflate this charge, to the detriment 2 of CCAs' competitive position.
3 Finally, PG&E’s proposal to recover these “generation” costs via the UOG Legacy, 2009, 2010, 2011, and 2012 PCIA vintages70 4 will impact different CCA customers 5 differently, depending on their departure date from bundled service (i.e., their assigned 6 vintage year). This is both unfair and illogical, as even PG&E has admitted that all customers will benefit similarly from the BMI project.71 7 8 IV. THE COMMISSION SHOULD NOT ALLOW PG&E TO RECOVER THE COSTS 9 ASSOCIATED WITH THE CC&B 25.1 UPGRADE AS BMI COSTS.
10 Q: Please summarize this portion of your testimony.
11 A: In this section of my testimony, I discuss PG&E’s unnecessary and unreasonable delay in 12 proceeding with its BMI process. This delay necessitated an interim step in the upgrade 13 process—implementation of the CC&B 25.1 upgrade—that will result in approximately $25 million of stranded costs.72 14 I do not evaluate in this testimony whether the CC&B 25.1 15 upgrade is necessary; instead, I focus here on the extent to which ratepayers should be 16 responsible for the costs associated with PG&E’s delays. 17 I recommend that the Commission either deny PG&E’s request to recover the costs 18 of the CC&B 25.1 upgrade as BMI costs, or disallow a return on rate base for the portion 19 of the BMI costs associated with the CC&B 25.1 upgrade and credit customers for the 20 associated stranded costs.
21 Q: Please explain PG&E’s planned CC&B 25.1 upgrade within the context of the BMI 22 process.
23 A: Stage 2 of PG&E’s BMI process includes updating the outdated version of Oracle Utilities 24 CC&B currently used by PG&E, version 2.4, to the up-to-date version 25.1. PG&E states 25 that “[r]ather than upgrade directly to C2M, PG&E evaluated (and ultimately selected) an 70 Attachment KJC-2 (PG&E Response to PCE DR 1.17).
71 Attachment KJC-2 (PG&E Response to PCE DR 2.28).
72 Attachment KJC-2 (PG&E Response to PCE DR 1.05).
41 1 option to perform an intermediate upgrade to stabilize PG&E’s CC&B system by upgrading to the most up-to-date version of Oracle’s CC&B program, CC&B 25.1.”73 2 3 PG&E has identified the upgrade to version 25.1 as a stabilization exercise that 4 provides a solution to several of the issues with the legacy billing system. PG&E states that 5 upgrading to this version will address the following issues: (1) allow PG&E to remedy the 6 cybersecurity vulnerabilities that are currently open and Oracle’s lack of support for the 7 current version of the system, (2) remedy the incompatibility with current versions of 8 PG&E’s software that are integral to its stable functioning, which has led to difficulties 9 performing disaster recovery exercises, (3) transition from COBOL to Java, which is the 10 language that C2M uses as well, and (4) bring the associated applications into support along with the CC&B system.74 11 PG&E believes that upgrading to CC&B 25.1 would address 12 issues with maintaining CC&B 2.4 for two or more years while waiting for C2M to go live.75 13
14 However, the CC&B 25.1 upgrade is not the target-state solution because it does 15 not enable multiple critical business outcomes that PG&E has identified. For example, the 16 CC&B 25.1 upgrade will not move from linear rates to modular rates, reduce the number 17 of customizations, integrate with an MDMA solution, or move PG&E to a single modular rate engine.76 18 Thus, PG&E proposes that the CC&B 25.1 system be replaced by the upgrade to C2M during Stage 3 of the BMI.77 19
20 Q: When will this CC&B 25.1 upgrade occur and what are the costs associated with it? 21 A: The CC&B upgrade to version 25.1 began in Q4 2024 and is currently forecasted for 22 completion by the end of 2026, as shown in Figure 6 below. The CC&B 25.1 upgrade is 23 projected to cost $127.5 million between 2024 and 2026, including $91.2 million in capital costs, $8.5 million in expense costs, and $27.8 million in contingency.78 24 73 PG&E Testimony, Chapter 4, pp. 4-28 to 4-29.
74 Id. at 4-29 to 4-30.
75 Id. at4-29.
76 Id. at4-30.
77 Attachment KJC-2 (PG&E Response to PCE DR 1.03).
78 PG&E Testimony, Chapter 6, p. 6-21.
42 Figure 6: Timeline for Billing Modernization Initiative79 1 Q: Please explain the role of the CC&B 25.1 upgrade in relation to the C2M upgrade 2 during Stage 3 of the BMI.
3 A: As mentioned above, the CC&B 25.1 system will be entirely replaced by the C2M system. 4 Essentially, PG&E describes the CC&B 25.1 upgrade as a temporary solution that is 5 necessary to provide a secure and reliable billing platform for customers until the implementation of the C2M system in 2029/2030.80 6 The C2M system will replace all 7 billing components and consolidate the electric Biling Cloud System (BCS) and Advance 8 Billing System (ABS) into one system.
9 Q: Will the CC&B 25.1 upgrade result in stranded costs since it will be fully replaced by 10 C2M?
11 A: Yes. PG&E admits that if it transitions directly from legacy systems to C2M—i.e., without 12 implementation of the BCS or CC&B 25.1 projects—there would be no stranded costs associated with the BMI.81 13 However, because the CC&B 25.1 system will be replaced by 14 C2M, PG&E states that 25 percent of the system component upgrade cost for CC&B 25.1, 15 or $24.7 million, is associated with investments that will no longer be utilized once C2M is implemented.82 16
79 PG&E Testimony, Chapter 1, p. 1-6, Figure 1-2.
80 Id. at 1-6.
81 Attachment KJC-2 (PG&E Response to PCE DR 1.26).
82 Attachment KJC-2 (PG&E Response to PCE DR 1.05).
43 1 Q: How did PG&E end up in this situation in which it will be investing significantly in 2 an interim upgrade (CC&B 25.1) that it will be fully replacing with its end-state 3 billing system (C2M) within a few years?
4 A: The CC&B 25.1 upgrade is an interim step that is necessary only because PG&E 5 substantially delayed implementation of C2M. PG&E originally planned to upgrade the 6 outdated CC&B 2.4 directly to C2M, with the C2M system’s implementation planned to go live in 2024, as proposed in PG&E’s 2023 GRC.83 7 However, since the Commission’s 8 rejection of PG&E’s proposal in the 2023 GRC—due to PG&E’s insufficient showing in that case 9
84—PG&E has continuously stalled its upgrade processes and forgone many 10 opportunities to keep its billing systems in adequate condition. 11 Q: What is PG&E’s explanation for its significant delays? 12 A: PG&E seems to suggest that the Commission’s rejection of its original billing upgrade 13 proposal in its 2023 GRC is the primary reason for this delay. PG&E explains that it moved 14 the current timeline for the potential implementation of the C2M system to 2026 after the rejection of PG&E’s billing upgrade proposal in the 2023 GRC.85 15 PG&E notes that this 16 delay led to further deterioration of the CC&B 2.4 system as the system became increasingly out-of-date, unsupported, and vulnerable to cyber threats.86 17 Additionally, 18 PG&E claims the recent completion of PG&E’s Plan, Analyze, and Design phase of C2M 19 revealed additional complexities in the direct upgrade from CC&B 2.4 to C2M pertaining 20 to requirements of a peak day pricing user interface, bill print extract functionality, and payment plans.87 21 Because of the continued deterioration of the CC&B 2.4 system and the 22 additional complexities associated with a direct upgrade from CC&B 2.4 to C2M, PG&E 23 asserts that the intermediate upgrade to CC&B 25.1 is needed to stabilize the billing 24 system.
25 Q: Was it reasonable for PG&E to continue to allow its CC&B 2.4 system to deteriorate 26 in this manner?
83 PG&E Testimony, Chapter 4, p. 4-26 and p. 4-27.
84 D.23-11-069, pp. 546-550.
85 PG&E Testimony, Chapter 4, p. 4-26 and p. 4-27.
86 Id. at 4-28.
87 Id. at 4-27 to 4-28.
44 A: No. PG&E upgraded from CC&B version 2.3 to the current CC&B version 2.4 in 2017.88 1 2 There have been at least five updated CC&B versions released by Oracle since version 2.4, 3 as shown in Table .

Table 5: Oracle Releases of CC&B Versions89
CC&B
Version Release Date
CC&B 2.4 October 2013
CC&B 2.5 October 2015
CC&B 2.6 May 2017
CC&B 2.7 August 2018
CC&B 2.8 April 2021
CC&B 2.9 April 2022
CC&B 25.190 April 2025
4 PG&E could have updated its CC&B system numerous times in the past but instead chose 5 to delay such an update until the BMI. This decision resulted in PG&E’s current situation 6 in which its CC&B system does not have standard vendor support and remediation options to address cyber vulnerabilities.91 7
8 Q: Are there other third-party sources that indicate this course of action was not 9 reasonable?
10 A: Yes. This delay was also contrary to the advice PG&E received as a result of multiple 11 outside consultant reviews. For instance, in a 2018 evaluation, Accenture recommended 12 that PG&E re-platform to a next generation CIS within the 2024 timeframe, and in a 2022 evaluation, Accenture reiterated the need to re-platform in the near-term.92 13 14 PG&E’s delay was also inconsistent with PG&E’s own articulation of its best 15 practices in these kinds of situations. PG&E notes in discovery that its optimal timeline for 16 analyzing IT asset replacement options is through routine check-ins performed as a regular 17 part of system maintenance as soon as the asset has been deployed and is operating without 88 Attachment KJC-2 (PG&E Response to PCE DR 2.03).
89 Id.
90 The table included in PG&E Response to PCE DR 2.03 incorrectly noted this version as being CC&B 25.4; it has been corrected in this table to reflect the proposed upgrade of CC&B 25.1. 91 PG&E Testimony, Chapter 1, p. 1-3.
92 Attachment KJC-2 (PG&E Response to PCE DR 1.22).
45 significant defects,93 1 and that its optimal timeline for undertaking asset replacement is 2 “within the operational lifespan of the asset[,]” which “[f]or most software and hardware . . . is typically between 3 to 10 years.”94 3 The aging billing systems at issue are fully 4 depreciated and “have more than fulfilled their asset lives[,]” with the original system implementation in 2001 and the most recent update occurring in 2017.95 5 Thus by waiting 6 until the end of 2024 to even file this Application, PG&E has strayed far beyond the 7 timelines for review and replacement it calls out as prudent. 8 Q: Could PG&E have approached the planning of the C2M upgrade differently to avoid 9 the need for the CC&B 25.1 upgrade?
10 A: Yes. I believe PG&E could have taken a few different reasonable courses of action to 11 prevent the situation in which it now finds itself.
12 First, PG&E could have prepared a more robust showing in its 2023 GRC that 13 provided the Commission with sufficient information to review and approve the billing upgrade request at that time.96 14
15 Second, even in the scenario in which PG&E provided that deficient showing in the 16 2023 GRC, following that 2023 GRC decision, it was fully within PG&E’s discretion to 17 determine when to file a new application for cost recovery approval of its billing system 18 upgrade. PG&E could have filed this Application earlier in 2024, and prior to Commission 19 approval of the Application, it could have requested authorization to track the costs 20 associated with necessary billing upgrade work in a memorandum account, to be later 21 reviewed by the Commission for reasonableness and cost recovery. With a memorandum 22 account in place, PG&E could have proceeded with its C2M implementation without delay, deployed C2M by the end of 2026 as planned,97 23 and avoided the need for the interim CC&B 24 25.1 upgrade.
93 Attachment KJC-2 (PG&E Response to PCE DR 1.20).
94 Id. (emphasis added).
95 PG&E Testimony, Chapter 2, p. 2-15.
96 See PG&E Testimony, Chapter 1, p. 1-11, Table 1-3 (listing all the directives from the 2023 GRC decision that describe the items that were missing from PG&E’s initial proposal in that case). 97 Attachment KJC-2 (PG&E Response to PCE DR 1.19).
46 1 Alternatively, even if PG&E was for some reason unable to file its Application 2 earlier, it could have filed a standalone request for authorization to track the costs 3 associated with necessary billing upgrade work in a memorandum account. With a 4 memorandum account in place, PG&E could have proceeded with the C2M upgrade, achieving implementation by the end of 2026 as discussed above,98 5 and it would not now 6 need to invest in the CC&B 25.1 upgrade and further delay C2M implementation. 7 Q: Why do you think requesting cost tracking via a memorandum account would have 8 been appropriate for these costs?
9 A: The Commission has a procedural mechanism available to IOUs so that they may proceed 10 with necessary and time-sensitive investments in the absence of upfront approval for full 11 cost recovery: memorandum accounts. While the Commission’s general practice “is not to 12 authorize increased utility rates to account for previously incurred expenses,” the 13 Commission commonly makes an exception when, “before the utility incurs those 14 expenses, the Commission has authorized the utility to book those expenses into a memorandum or balancing account for possible future recovery in rates.”99 15 Memorandum 16 accounts are routinely used to track these kinds of time-sensitive investments so that a 17 utility can proceed with what it deems to be necessary or prudent work, and later seek cost recovery for the associated costs.100 18
19 Q: Given all this context, do you think PG&E’s approach to its C2M implementation 20 was reasonable?
21 A: No. It appears that PG&E has delayed C2M implementation and delayed CC&B upgrades 22 several times because it was not yet guaranteed through a Commission decision that it 98 Id.
99 In the Matter of the Application of Southern California Water Company for authority pursuant to Public Utilities Code Section 851 to sell, and, if necessary, lease back its headquarters property in Los Angeles, California (U 133 M), D.92-03-094, 1992 Cal. PUC LEXIS 236, *7-9. See also D.23-05-003, p. 5 (“The courts have accepted that when the Commission approves of the scope of a program in advance, and when there is a subsequent review of the reasonableness of the utility’s decision-making and management of the program, then forecast costs can subsequently be ‘trued up’ to actual and any revenue shortfall or overcollection is recoverable by the utility or refundable to ratepayers. The preapproval of the scope of the balancing account averts a finding of retroactive ratemaking, i.e., it becomes an exception to the test year forecast requirement.”).
100
See, e.g., D.21-08-024; D.19-01-019; D.09-07-038; D.03-05-076. 47 1 would get full cost recovery for these investments. This is not a reasonable course of action. 2 It is not prudent for a utility to put itself in a situation in which it is vulnerable to cyber 3 security threats and is operating unsupported software—especially when the associated 4 software is key to the management of customer billing and data. It is also not reasonable 5 for a utility, in an effort to secure cost recovery approval prior to taking action, to delay 6 billing upgrades to the point that its customers must then bear significant incremental 7 costs—$25 million of which will ultimately be stranded costs. 8 Q: In light of PG&E’s inappropriate approach to the C2M upgrade, how should the costs 9 associated with the CC&B 25.1 upgrade be treated?
10 A: Given PG&E’s unreasonable delay in moving forward with its billing system upgrades, I 11 recommend that the Commission deny PG&E’s request to recover the costs of the CC&B 12 25.1 upgrade as BMI costs, which is estimated to be $119 million of capital costs and $8.5 million of O&M expense.101 13
14 In the alternative, if the Commission allows PG&E to include the CC&B 25.1 15 upgrade costs as part of the BMI, then PG&E should not be allowed a return on rate base for this portion of the BMI costs, which is estimated to be $119 million.102 16 Additionally, 17 the Commission should order PG&E to reimburse customers for the $24.7 million in 18 associated investments that will not be used in the final C2M system. This recommendation 19 is in line with the example set by SCE in its ERP reimbursement proposal in A.25-03-009. 20 In that case, SCE plans to reimburse customers for ERP benefits associated with O&M and 21 capital expenditures no longer needed for the ERP program but anticipated to be authorized 22 in SCE’s 2025 GRC. Furthermore, savings associated with O&M or capital expenditures 23 no longer required due to the ERP program upgrades in 2029 and beyond and not 24 anticipated to be requested in SCE’s future GRCs will be returned to customers in SCE’s 25 future GRCs through lower recorded costs, specific line-item reduction to capital or O&M forecasts, and/or SCE excluding incremental forecast costs.103 26 101
PG&E Testimony, Chapter 1, Table 1-1.
102
Id.
103
A.25-03-009, Application of Southern California Edison Company (U 338-E) for Authorization to Recover Costs Related to NextGen Enterprise Resource Planning Program, Testimony-Volume 2, pp. 77-

78. 48
1 V. THE COMMISSION SHOULD HOLD PG&E ACCOUNTABLE FOR ENSURING 2 THE BMI FIXES CERTAIN PERSISTENT BILLING PROBLEMS, IMPROVES 3 PG&E’S PERFORMANCE ON DESIGNATED BILLING SYSTEM EFFICIENCY 4 METRICS, AND ACHIEVES TARGET TIMELINES FOR CRITICAL GOALS. 5 Q: Please summarize this portion of your testimony.
6 A: In this section of my testimony, I recommend that the Commission order PG&E to ensure 7 its substantial BMI investment addresses certain persistent billing issues experienced by 8 CCAs and CCA customers and measurably improves PG&E’s performance on key billing 9 system efficiency metrics. I also recommend that the Commission hold PG&E accountable 10 for achieving set timelines for the implementation of its many backlogged rate projects and 11 for resolving any CCA billing and revenue delays arising out of the BMI deployment. The 12 Commission should not approve this level of investment in PG&E’s billing system without 13 concrete commitments from PG&E that its new system will effectively address the 14 significant problems plaguing its legacy billing systems and approach, with minimal 15 disruption to customers.
16 E. The Commission Should Order PG&E to Ensure its BMI Investment 17 Addresses Certain Persistent Billing System Problems. 18 Q: What kinds of billing system issues are CCAs and CCA customers experiencing on a 19 regular basis?
20 A: Based on my discussions with representatives from the CCAs’ data management providers, 21 my understanding is that the most pervasive billing issues experienced by the CCAs under 22 PG&E’s current billing system fit into the following general categories: (1) data access; 23 (2) data quality; (3) communication and coordination; and (4) billing mechanics challenges 24 and delays.
25 Q: Can you explain the issues CCAs have been experiencing with data access? 26 A: In PG&E’s current billing system, there is certain critical billing data to which CCAs and 27 their data management providers do not have access. In the table below, I provide a list of 28 additional data needed and explain why in each case it is vital for CCAs to have access to 29 the data.
49 Table 6: Additional Data Needed by CCAs in End-State PG&E Billing System Data File Description Why CCAs Need Access
Hourly and Sub-Hourly Billing
Interval Data
PG&E Electronic Data
Interchange (EDI) billing
transactions still only provide
scalar usage aggregated by
time-of-use (TOU) period,
unlike SCE and SDG&E which
have included interval data for
approximately 10 years.

Scalar data is inadequate for
dynamic pricing, energy
efficiency programs, and many
other key functions to CCA
business. The absence of
interval data effectively
prevents CCAs from creating
their own rate schedules,
dynamic pricing programs, or
even different TOU hours.

PG&E’s workaround of using
the ShareMyData (SMD)
platform for the last decade is
not an adequate solution. CCAs
need to bill on the EDI
transactions supplied by
PG&E. Furthermore, SMD data
is not utilized by PG&E for
billing; therefore the data is not
fully processed or reliable.

This level of data should
already be required to be
provided to the CCAs today.

The Commission should order
PG&E to provide this level of
detail by the end of 2025 and
ensure that this level of detail
will still be able to be provided
upon conclusion of the BMI
project.
50 810 Files for “Rate
Ready”104
Accounts
An 810 file is an EDI file type
that consists of a detailed
customer invoice (e.g., it
includes all the separate
transactions that comprise the
total bill).

Currently, for “Rate Ready”
accounts, CCAs do not receive
detailed invoice files from
PG&E.

Having 810 files for these
accounts will allow CCAs to
(1) provide better service to
customers and help customers
understand their charges, and
(2) validate individual
transactions and confirm the
accuracy of these customers’
bills.

Expected Versus
Sent
Usage/Account
Reporting
An 814 file is an EDI file type
that provides account
attributes; an 867 file is an EDI
file type that provides usage
data.

Currently, the CCAs receive
these 814 and 867 files every
day from PG&E, but they do
not have sufficient insight into
situations in which these files
are unexpectedly missing for
particular accounts.

Daily reports on the expected
versus actually sent EDI 814
and EDI 867 counts would
allow CCAs to track delays or
items of concern in PG&E-CCA data exchange.
104
There are two types of billing available to PG&E CCAs: “Rate Ready” and “Bill Ready.” “Rate Ready” accounts operate as follows: the CCA gives PG&E its rates, and PG&E then uses its billing system to calculate the invoice for CCA services. In contrast, “Bill Ready” accounts operate as follows: PG&E sends the CCA/CCA Data Manager its usage data, and then the CCA/CCA Data Manager calculates the invoice amount and sends PG&E an invoice to be placed on the consolidated bill. 51 Adding the “Billed
To” Date in 4013
Files
A 4013 file is an Excel/CSV
file type that consists of a
weekly snapshot of all active
accounts in a given CCA
territory (also referred to as a
“Customer List”).

Currently, this file type does
not include a “billed to” date
(i.e., the last date PG&E billed
the account).

CCAs have a list of PG&E
accounts with usage
transactions missing. This can
be due to issues with PG&E’s
billing system. In other cases
CCAs have identified inactive
accounts incorrectly left open.

Adding a “billed to” date field
in this file would give CCAs
more insight into which
accounts have missing
customer usage information—a
common issue that leads to
delayed billing and back
billing.

Daily API Pushes
Sharing 4013 Data
The manual method by which
PG&E shares 4013 file data
with the CCAs via weekly
postings is onerous for both
PG&E and the CCAs.

Creating an Application
Program Interface (API)
connection where daily
changes to 4013 data could be
pushed to the CCAs would
reduce storage and manual
processes on both the PG&E
and CCA sides.

Including “White
Bill” Data on
“Blue Bills” for
Solar/Storage
Customers
PG&E currently does not
include the detailed
information from its “white
bills” in its regular “blue bills”
for solar/storage customers.

Including the information
currently included on “white
bills” within PG&E’s “blue
bills” would enhance bill
clarity and facilitate customer
understanding. Once this is
accomplished, “white bills”
should be discontinued.
52 1 Q: What do you recommend with respect to data access? 2 A: The Commission should order PG&E to provide the data files included in Table 6 above 3 to CCAs as a regular course of business once it has transitioned to its final end-state billing 4 system via the BMI. However, with respect to hourly and sub-hourly interval data, PG&E 5 should be required to provide this data sooner. Specifically, PG&E should be required to 6 provide the hourly and sub-hourly data to CCAs by no later than the end of 2025. The 7 hourly and sub-hourly data has been provided by SCE and SDG&E for nearly 10 years. 8 Q: Can you explain the issues CCAs have been experiencing with data quality? 9 A: It is my understanding from conversations with representatives from the CCAs’ data 10 management providers that many of the data files PG&E shares with CCAs in the normal 11 course of providing billing services are often incomplete or error ridden. In the table below, 12 I provide a list of the data quality issues experienced by the CCAs and how PG&E’s post-13 BMI end-state billing system should address them.

Table 7: Data Quality Fixes Needed in End-State PG&E Billing System Data Quality
Issue
Description of Data Quality
Problem
Data Quality Solution
No Clear Process
for Resolving
Unbilled
Invoices (810
Files)
An 810 file is an EDI file type
that consists of a detailed
customer invoice. It is
currently used for “Bill Ready”
accounts; per the Joint CCAs’
suggestion in Table 6 above,
810s should be provided for
“Rate Ready” accounts as well.

Currently, PG&E does not
adhere to any clear process for
resolving unbilled 810 files.

These are accounts that are
billed by the CCA, but there is
no acknowledgement from
PG&E if CCA charges have
been presented to the customer.

There should be an established,
enforceable service level
expectation that PG&E must
provide full resolution within
three business days once it
receives notice from a CCA of
unbilled invoices. This will
ensure CCAs can get the
revenues they are due in a timely
manner.
53 Inconsistency in
Classification of
Rate Changes
(814 Files)
An 814 file is an EDI file type
that provides account
attributes. PG&E has a practice
of inconsistently classifying
account rate changes—
sometimes it classifies them as
an “814 Rate Change”;
sometimes it classifies them as
an “814 Enrollment”; and
sometimes it classifies them as
an “814 Other” transaction.

This affects how these files are
processed in automation and
where they appear in reports.

Any rate change should be sent
via an 814 file and classified as
“814 Rate Change” to avoid
confusion.

Unclear
Drop/Enrollment
Transaction Data
PG&E has a practice of
communicating about all
customer drops and
enrollments via 814
transactions (the EDI file type
that provides account
attributes). When there are
multiple drop/enrollment
transactions on the same day
for an account, PG&E does not
clearly differentiate between
the transactions with precise
date/time stamps or indicate the
final state (i.e., “Active” or
“Closed”) of the account.

PG&E should clearly
differentiate between all
drop/enrollment transactions
with precise date/time stamps
and indicate the final state (i.e.,
“Active” or “Closed”) of the
account.

Inconsistent
Communication
of Usage Data
PG&E is inconsistent in how it
sends customer usage data to
the CCAs. Sometimes PG&E
sends usage data via EDI, but
other times it states it cannot do
so, and must instead provide
the data via spreadsheet or via
its green button AMI platform.

PG&E should send all usage data
via EDI. This will streamline
data transfer and minimize
significant additional work on
the CCA side.
54 Usage Data Sent
Without
Enrollment Data
PG&E often sends CCAs
customer usage data without
any corresponding enrollment
data for the customer account.

When the CCA receives usage
without an enrollment, CCAs
are unable to load that usage
data into their billing systems
without manual follow-up.

PG&E should be required to
consistently send 814 files
whenever a new customer
enrolls.

Unauthorized
Invoice
Cancellation
In instances in which there is
duplicate usage in a bill period
in error, PG&E at times will
cancel CCA charges without
CCA authorization.

PG&E should never cancel CCA
charges unless it receives
authorization to do so from a
CCA.

Errors in PG&E
Files Sent to
CCA Banks
Currently, PG&E’s process for
sending credit and debit
transactions to CCAs’ banks is
problematic. PG&E limits the
number of transactions it sends
in one file, and it sends all
credit transactions first,
followed by all debit
transactions. This causes issues
with file receipt and
processing.

PG&E should be required to
streamline its process for sending
files to CCAs’ banks, including
by sending all transactions at
once (without dividing credit and
debit transactions).

Process For
Switching From
Rate Ready to
Bill Ready
PG&E has no good way of
indicating when customers
switch from Rate Ready to Bill
Ready accounts. Currently,
PG&E sends a drop notice and
then a change request, which is
cumbersome and causes
unnecessary manual work.

PG&E should approach this in a
simpler way: when a customer is
switching from Rate Ready to
Bill Ready, this should always be
indicated via an 814 Change
Form.

Inability to Audit
Rate Ready
Accounts
CCAs are unable to audit Rate
Ready customer bills because
CCAs do not receive detailed
invoice files from PG&E for
these accounts.

PG&E should ensure CCAs can
audit bills for Rate Ready
customers. This could be
achieved (1) if PG&E provides
810 files for these accounts, as
proposed in Table 6 above, or (2)
if PG&E provides more
information via its 248 files
(billing confirmation files)
associated with the Rate Ready
accounts.
55 Incorrectly
Sending Both
Interval and
Scalar Usage
There are two types of usage
data PG&E can provide:
interval read (15 minute or
hourly data for entire billing
period) or scalar read (total
kWh per billing period,
sometimes broken up between
TOU buckets).

PG&E at times sends scalar
data and then follows up later
with interval data for the same
accounts. This is unnecessary
and causes manual work on the
CCA side.

PG&E should only send one type
of usage data per account per
billing period.

Per the recommendation
regarding interval data in Table 6
above, PG&E should always be
sending just interval data.
1 Q: What do you recommend with respect to these data quality issues? 2 A: The Commission should order PG&E to ensure that its post-BMI end-state billing system 3 will address the data quality issues summarized in Table 7 in accordance with the 4 recommendations therein.
5 Q: Can you explain the issues CCAs have been experiencing with communication and 6 coordination between the billing teams at PG&E and those at the CCAs? 7 A: Based on my conversations with CCA representatives as well as the CCAs’ data 8 management providers, in general it seems that PG&E is directing insufficient resources 9 toward resolving CCA customer billing issues and delays in a timely manner. PG&E does 10 not have designated points of contact for resolving technical billing issues or ongoing, 11 collaborative working groups dedicated to resolving CCA billing issues and delays. 12 Given this context, the CCAs are concerned that the various stages of BMI rollout 13 will not be communicated with sufficient detail or notice to CCAs and their customers. 14 This concern is reinforced by the lack of detail provided in PG&E’s Application and 15 Testimony on this point. PG&E has not clearly explained how the various BMI changes 16 will be communicated, acknowledging that “most PG&E customers do not have account 56 1 representatives, so the C2M project will need to differentiate its approach to communicate the changes to customers”105 2 but failing to specify how it will “differentiate its approach.” 3 Q: What are your recommendations with respect to ensuring effective communication 4 and coordination between the PG&E and CCA billing teams? 5 • The Commission should order PG&E to provide a designated point of contact for 6 resolving technical billing issues impacting CCAs, in line with common practices at 7 other California IOUs.
8 • The Commission should order PG&E to hold a semi-annual PG&E-CCA stakeholder 9 workshop on resolving outstanding technical billing issues. 10 • The Commission should order PG&E to clarify, via an advice letter filing, its plan 11 regarding how and when it will communicate with various customer groups on major 12 upcoming changes arising out of the BMI. The Commission should also set a minimum 13 timeframe for such communications, and specifically, order that PG&E must notify and 14 educate customers and CCAs about all major upcoming billing changes arising out of the BMI at least three months in advance of implementation.106 15 16 Q: Can you explain the issues and concerns CCAs have with billing mechanics and 17 delays?
18 A: Yes. Based on my conversations with CCA representatives, there are several key items of 19 concern:
20 • Delays in switching rates. CCAs experience excessive delays in getting some 21 customers switched from one rate to another. For example, SVCE highlighted a 22 situation in which it took nearly eight months to move an account from a TOU-C 23 rate to an E-ELEC rate. When this change was finally implemented, it resulted in a 24 large balloon payment due from the customer. These types of delays cause customer 25 experience issues, and in the aggregate, they could have anticompetitive impacts. 26 • Inaccurate application of bill credits. When a CCA issues a credit on a 27 customer’s bill that is greater than the generation charges on the bill, the credit 105
PG&E Testimony, Chapter 5, p. 5-46.
106
Id.
57 1 flows to the PG&E charges on the bill. Meaning, PG&E takes the CCA credit and 2 applies it to the electric transmission, electric distribution, or gas portion of the bill 3 instead of holding the credit to be applied to future generation charges. This 4 effectively is causing the CCA to pay for those services on behalf of customers. 5 • Backlogged billing projects. In general, PG&E has been unable to develop new 6 billing functionalities in a timely manner due to its backlog of projects. As one 7 example, PG&E maintains that it cannot commit to enabling tariff on-bill (TOB) program billing functionality,107 8 even though it acknowledges that current billing functionality enabling on-bill financing (OBF) cannot support TOB. 108 9 PG&E has
10 stated in the TOB proceeding (Rulemaking 20-08-022) that it will not be able to 11 implement a new TOB line item in the billing system before 2030 without requiring 12 trade-offs with other projects. However, in Testimony in this case, PG&E 13 acknowledges that the BMI end-state system must be able to manage the anticipated continued addition of new and more complex rates.109 14 TOB would be such an 15 addition, and it is unclear why PG&E’s BMI proposal does not contemplate a 16 specific plan and timeline for enabling TOB program billing functionality. 17 Q: What are your recommendations with respect to these issues around billing 18 mechanics and delays?
19 • The Commission should order PG&E to design its final end-state billing system to 20 efficiently switch customers between rate schedules when requested. This process 21 should not take longer than one month.
22 • The Commission should order PG&E to design its final end-state billing system to 23 allow for the escrow of CCA bill credits so that these credits are maintained on the 107
TOB financing is classified as a utility investment in behind-the-meter resources. TOB requires a new utility tariff with a cost recovery charge on the utility portion of the bill. The charge is tied to the meter and is applied to the account associated with the meter; when the account holder changes, the TOB charge is automatically applied to the next account holder. 108
R. 20-08-022, Pacific Gas and Electric Company’s (U39 M) Reply Comments on Administrative Law Judge’s Ruling Directing Parties to File Comments on Tariff On-Bill Proposals, pp. 1-4 (May 30, 2025).
109
PG&E Testimony, Chapter 4, p. 4-5.
58 1 generation side of the bill (thus avoiding a situation in which the CCAs are paying for 2 the PG&E side of the bill).
3 • The Commission should order PG&E to commit to preparing its billing system to 4 enable TOB functionality by the time Phase 3 of the BMI is completed. 5 F. The Commission Should Order PG&E to Ensure its BMI Investment Results 6 in Improvements on Key Billing System Efficiency Metrics. 7 Q: Has PG&E provided any insight into how the BMI will increase efficiencies in the 8 CCA billing process?
9 A: PG&E explains that the “BMI is expected to enhance the efficiency and automation of 10 several processes related to CCA services,” likely resulting in reduced manual intervention as certain activities “become more streamlined and system driven.”110 11 PG&E notes these 12 services “are expected to benefit from automation, improved data handling, and reduced administrative effort under the upgraded system.” 111 13 In terms of the specific changes or 14 upgrades in the BMI that PG&E expects will improve efficiency in CCA billing, PG&E 15 explains that at this point it has identified only “potential areas of improvement,” and does 16 not have “a comprehensive or final list, as PG&E is still in the early stages of the BMI 17 program” and “[m]any specific features have not yet been finalized, confirmed, or prioritized for implementation, particularly those planned for later phases (Stage 3).”112 18 19 Q: How can the Commission hold PG&E accountable for billing system efficiency 20 improvements and ensure PG&E’s investments in BMI result in an improved billing 21 experience for customers?
22 A: The Commission should not approve PG&E’s request for such substantial investments in 23 its billing system without establishing clear performance and timeline targets that PG&E 24 must meet in its end-state billing system. By requiring PG&E to track, report, and improve 25 upon its key billing system efficiency metrics, the Commission can hold PG&E 110
Attachment KJC-2 (PG&E Response to PCE DR 2.09).
111
Id.
112
Attachment KJC-2 (PG&E Response to PCE DR 2.10).
59 1 accountable for actually effectuating the efficiency improvements it claims the BMI will 2 provide.
3 Q: Do you have recommendations regarding the specific billing metrics PG&E should 4 track and improve upon?
5 A: Yes. The following metrics are ones that PG&E currently tracks; it should be required to continue to track, report on, and improve upon these metrics.113 6 These metrics are:
7 • Unbilled Revenues – monitors billed revenue that is uncollectible due to timing, system constraints, or limitations defined under Rule 17.1.114 8 9 • Quality Assurance Standard – late commencing bills; tracks bills issued more than 60 days after service start.115 10
• Delayed Bills – identifies bills not generated within 35 days of the previous bill date.116 11 12 • Customer Initiated Request Open > 45 Days – measures the percentage of service or billing-related request that remain unresolved more than 45 days after initiation.117 13 14 Q: What levels of improvement in these metrics should the Commission order PG&E to 15 target through its BMI?
16 A: I am not aware of how PG&E is performing regarding these metrics with its current billing 17 system. However, the Commission should order PG&E to file a report identifying the 18 results of these metrics as of the end of 2023 and 2024, and quarterly going forward. PG&E 19 should be required to file quarterly reports on these metrics, with the additional requirement 20 that each quarter, improvements should be achieved over the previous quarter metrics until 21 PG&E can justify that any further improvements in the metrics are economically infeasible. 22 The Commission should also ensure reporting on these targets incentives improvements by 23 adopting consequences for PG&E’s failure to continue to improve upon these metrics on a 24 quarterly basis.
25 Finally, it is critical that these metrics are tracked by bundled versus unbundled 26 customer status for a few reasons. First, this will allow the CCA-only data to be shared 113
Id.
114
Attachment KJC-2 (PG&E Response to PCE DR 2.10(b)).
115
Id.
116
Id.
117
Id.
60 1 with the CCAs’ billing providers as a regular course of business. Second, this will provide 2 transparency into any discrepancies in service level between the two customer types. 3 G. PG&E Should be Held Accountable for Achieving Certain Timing Targets in 4 the BMI Rollout.
5 Q: How else can the Commission hold PG&E accountable for ensuring its BMI achieves 6 its stated goals and improves customer experience?
7 A: In addition to my recommendations above regarding how to ensure PG&E is accountable 8 for addressing the problems with its current billing system and improving its performance 9 on key efficiency metrics, I also recommend the Commission hold PG&E accountable by 10 enforcing set timelines within which PG&E must achieve specific goals as it rolls out its 11 BMI. Specifically, with respect to the rollout of the BMI, the Commission should order 12 PG&E to: (1) commit to specific dates certain for achieving implementation of its 13 backlogged rate projects, and (2) commit to a specific timeline of seven business days for 14 resolving any CCA billing and revenue delays arising out of the BMI deployment. 15 Q: Are there specific implementation items for which PG&E does not currently provide 16 target implementation dates?
17 A: Yes, there are a lot. In its Testimony, PG&E provides a table with 26 different backlogged 18 rate implementation projects, designating the “planned completion year” for each. Of these 26 items, PG&E states that the completion year for 16 of them is “not yet planned.”118 19 20 Q: Is it reasonable for PG&E to decline to commit to a timeframe for implementation of 21 all these items?
22 A: No, it is not. The limitations of PG&E’s current billing system—combined with PG&E’s 23 delay in transitioning to a newer, more functional system—have contributed to this 24 significant backlog of rate implementation projects. PG&E asserts that one of the benefits 25 of the BMI is that it will allow PG&E to implement these backlogged projects “more efficiently.”119 26 If PG&E is requesting that ratepayers spend nearly $400 million on its BMI, 27 it should be required to assess the efficiencies that the BMI will bring and commit to 28 completing these projects on a designated timeline.
118
PG&E Testimony, Chapter 4, pp. 4-18 to 4-19.
119
PG&E Testimony, Chapter 6, pp. 6-9 to 6-10.
61 1 Q: What customer harm might result if PG&E is not held to specific deadlines for 2 completing these projects?
3 A: When PG&E faces resource limitations, it often deprioritizes projects that are of high 4 importance to CCAs and CCA customers. One example of this is PG&E’s long delay in 5 breaking out the PCIA as a line-item on customer bills, discussed above. This pattern 6 highlights that PG&E does not have any incentive to prioritize projects that are important 7 to CCAs. However, CCA customers represent over half of PG&E’s customer base; 8 deprioritizing items of concern to these customers harms the majority of PG&E’s 9 customers.
10 Q: What is your specific recommendation with respect to these backlogged rate 11 implementation projects?
12 A: The Commission should order PG&E to submit supplemental testimony designating 13 specific dates certain for achieving implementation of these 16 rate implementation projects. 14 Q: Do you have any other concerns regarding PG&E’s timelines—or lack thereof—for 15 addressing items that may arise in the course of the BMI rollout? 16 A: Yes. Based on its Testimony, it does not appear that PG&E is has any contingency plans 17 for handling any delays to the issuance of CCA bills or to the remittance of CCA revenues 18 caused by the BMI deployment.
19 Q: Why might such delays occur, and how would such delays affect CCAs? 20 A: PG&E’s Testimony regarding the BMI implementation does not appear to include any 21 testing plans to ensure that post billing activities occur without delay or issue. PG&E notes 22 that defects are expected to occur in the conversion process and must also be thoroughly tested and remediated;120 23 however, the list of testing does not appear to include testing for this type of activity.121 24 The proposed list of testing includes testing to ensure the data has 25 converted properly, the PG&E employees have completed user acceptance testing, and that 26 disaster recovery testing is complete. However, there is no testing identified to ensure post 27 billing activities do not result in delays to data sharing with the CCAs, billing for CCAs, 28 or the remittance of funds to CCAs. Depending on the magnitude of the delay, these kinds 120
PG&E Testimony, Chapter 5, p. 5-42.
121
Id.
62 1 of issues could be hugely impactful to the CCAs’ financial health as well as their ability to 2 serve their customers.
3 Q: What do you recommend to protect against this kind of CCA and customer harm? 4 A: The Commission should order PG&E to ensure via its planned testing processes that all 5 post billing processes are unaffected and that there are no delays to data sharing with the 6 CCAs, billing for CCAs, or the remittance of funds to CCAs. In the event that the go-live 7 of the BMI results in any unforeseen issues that affect the issuance of CCA generation bills 8 or the remittance of CCA revenues, PG&E should be required to resolve the issue within 9 seven business days. To ensure this kind of timeline is feasible, the Commission should 10 order PG&E to submit supplemental testimony that outlines its contingency plan for these 11 scenarios, including how it plans to resolve any such deployment issues within seven 12 business days.
13 VI. THE COMMISSION SHOULD REQUIRE PG&E TO CLEARLY OUTLINE THE 14 BMI’S LIKELY IMPACT ON CCA SERVICE FEES AND COMMIT TO SERVICE 15 FEE UPDATES POST-BMI IMPLEMENTATION.
16 Q: What are CCA service fees?
17 A: There are various services that PG&E charges CCAs fees for, including the establishment 18 of CCA service, notifying customers, customer enrollments, opt-out requests, meter data 19 management services, billing services, termination of CCA service, phase-in services, and 20 specialized services. These services are outlined in PG&E’s Electric Schedule E-CCA. 21 These fees are developed based on the estimated materials, labor time, system usages, and administrative effort needed to perform each service.122 22 23 Additionally, the customer re-entry fee—currently $4.24 per account—for 24 customers switching back to PG&E bundled service after the CCA opt-out period has 25 expired, is used to forecast the administrative cost component of the Financial Security Requirement (FSR) for CCAs.123 26 The re-entry fee for SCE is $0.40 per account and for SDG&E is $0.56 per account.124 27 The FSR is the amount CCAs are responsible to post with 122
Attachment KJC-2 (PG&E Response to PCE DR 2.11).
123
PG&E Electric Rule No. 23, Sheet 76.
124
SCE Schedule CCA-SF, Section H.1; SDG&E Schedule CCA, line 14. 63 1 their local IOU or Provider of Last Result (POLR) to ensure that a POLR can recover costs 2 and expenses incurred to re-enroll and serve CCA customers returning to bundled service 3 in case of a CCA’s failure.
4 Q: Does PG&E provide any insight through its testimony or discovery responses into 5 whether the BMI will lead to lower CCA service fees?
6 A: PG&E anticipates that it will continue to use a cost-based methodology similar to the 7 methodology it uses currently for CCA fees after the BMI is implemented, and it has not 8 committed to any specific changes in CCA fees post-implementation. Instead, PG&E has 9 indicated that some aspects of the BMI upgrades may cause fee decreases, while others 10 could cause fee increases.
11 In terms of factors possibly leading to fee reductions, PG&E explained the upgrades 12 associated with the BMI are expected to drive operational efficiency in supporting CCA-13 related services due to increased automation, data standardization, and streamlined workflows.125 14 In particular, reduced manual intervention is expected to improve efficiency 15 and reduce the risk of human error for certain processes, although the reductions in 16 administrative effort may not directly translate into lower service fees, according to PG&E.126 17 Additionally, PG&E expects that the transition to C2M will improve efficiency 18 in managing and supporting third-party energy services, although PG&E could not confirm at this time if these improvements will directly result in lower CCA service fees.127 19 20 However, PG&E has also indicated that other factors weigh in favor of CCA service 21 fees increasing post-BMI implementation. PG&E explained there could be incremental 22 regulatory requirements associated with POLR implementation, new data privacy and 23 compliance mandates, and customer billing and notification enhancements that may 24 increase costs associated with system enhancements and workload. Additionally, PG&E 25 confirmed that it will continue to apply an inflation or escalation factor to CCA service 125
Attachment KJC-2 (PG&E Response to PCE DR 2.11).
126
Id.
127
Attachment KJC-2 (PG&E Response to PCE DR 1.06).
64 1 fees to reflect expected labor cost growth, which could increase certain CCA service fees over time.128 2
3 Q: Has PG&E made a sufficient showing regarding the potential impacts of the BMI 4 upgrades on CCA service fees?
5 A: No. The Commission should require PG&E to outline the likely impacts to CCA service 6 fees in more detail in a supplemental filing. Many if not all of PG&E’s CCA service fees are calculated based on the labor time associated with the service.129 7 PG&E should be 8 required to lay out its forecasts regarding (1) how, if at all, the BMI will impact how each 9 service is performed, (2) any efficiencies PG&E hopes to capture with respect to its 10 provision of each service as a result of the BMI investments, and (3) how, if at all, PG&E 11 anticipates the fee level may change as a result. While there is no dispute that PG&E cannot 12 commit to specific fee reductions at this point, PG&E nonetheless can and should provide 13 more detail regarding how it intends through these upgrades to improve upon its current 14 CCA services.
15 Q: Has the Commission provided any guidance on this issue? 16 A: Yes, specifically in the context of the customer re-entry fee. The POLR Phase 1 Decision 17 (D.24-04-009) states: “As part of any future showing for its Billing System Upgrade 18 Project, PG&E should describe whether the project is expected to increase the level of 19 automation associated with CCA and ESP customers returning to PG&E’s bundled service.”130 20 PG&E notes in Testimony that the development of the Market Transaction 21 Management (MTM) Module “will enable customers to seamlessly transition to bundled 22 services if a third-party provider voluntarily or involuntarily leaves the market, minimizing 23 service disruptions and maintaining reliable customer experiences. MTM introduces 24 functionality that is expected to allow PG&E to return an entire CCA population to bundled service next day with minimal impacts on billing and the customer experience.”131 25 128
Attachment KJC-2 (PG&E Response to PCE DR 2.11).
129
See PG&E Electric Schedule E-CCA.
130
D.24-04-009, p. 43.
131
PG&E Testimony, Chapter 4, p. 4-45.
65 1 Thus while PG&E has provided some information in this case on how the BMI will 2 increase automation associated with the return to bundled service, it has not explicitly 3 discussed or committed to any particular timeline for passing along the savings of those 4 efficiencies to customers. Currently, the re-entry fee used to estimate the administrative 5 cost component of a CCA’s FSR is based on the salary and time it would take a PG&E 6 customer service employee to manually transfer a CCA customer back to bundled services. 7 If BMI implementation automates a customer’s transition from unbundled to bundled, the 8 re-entry fee should either be reduced or become obsolete, therefore reducing or eliminating 9 the administrative cost component of FSR.
10 This example illustrates the importance of PG&E detailing how the BMI might 11 impact CCA service fees, and committing to a timeline for reviewing the costs associated 12 with these services promptly post-BMI implementation to ensure these cost savings are 13 passed on to customers. While this example is in the context of the re-entry fee, this same 14 reasoning applies to the other CCA service fees as well. 15 Q: What should the Commission do to ensure any efficiencies achieved by the BMI 16 translate into concrete customer benefits?
17 A: The Commission should order PG&E to file testimony in a formal proceeding (via a GRC 18 or through a separate Application) within a year of final implementation of the end-state 19 BMI billing system that reviews PG&E’s CCA service fees. This testimony should provide 20 PG&E’s new proposed CCA service fee levels and justify these fee levels based on the 21 costs PG&E incurs to perform the services in its new billing system. 22 Q: Does this conclude your testimony?
23 A: Yes.
24 25
Attachment KJC-1
CV of Kyra J. Coyle
KYRA J. COYLE
Principal
Economics | Strategy | Stakeholders | Sustainability
www.newgenstrategies.net

CONTACT
225 Union Blvd., Ste 450
Lakewood, Colorado 80228
[email protected]
www.newgenstrategies.net

EDUCATION
Bachelor of Arts, Business
Administration with emphasis in
Accounting, Dakota Wesleyan University
Minor, Computer Applications, Dakota
Wesleyan University

KEY EXPERTISE
Accounting
Budgeting
Contract Negotiations
Financial Modeling
Forecasting
Project Management
Regulatory Affairs
Strategic Planning
Ms. Kyra Coyle has over 15 years of experience in the utility, mining, and public accounting sectors and joined NewGen as a Senior Manager in December 2023 and has been promoted to a Principal as of January 2025. Her expertise includes utility revenue requirement analyses, strategic planning, project management, contract negotiations, financial modeling, regulatory affairs, budgeting, forecasting, and regulatory accounting. Her rate-related projects have included studies to develop retail electric, natural gas, transmission, ancillary service, standby and special contract rates.

Ms. Coyle has provided expert witness testimony on revenue requirement cost of service issues before public utility commissions and the Federal Energy Regulatory Commission. She has also offered other types of cost of service and rate-related litigation support.

PRIOR RELEVANT EXPERIENCE
Black Hills Corporation
Director of Regulatory/Finance – Wyoming, Montana and
South Dakota Electric and Natural Gas Utilities
 Provide strategic leadership for all financial and regulatory matters for electric and natural gas utilities.
 Direct the development and filing of rate case applications and other regulatory filings supporting the Company’s strategic plan, including new and innovative tariff offerings to incentivize economic development.  Financial leader executing strategy for long-term success, responsible for $1.9 billion of rate base. Received approval for a large transmission project (~260 miles).
 Contract negotiations with large, high density, power customers, including cost allocations for generation and transmission.
 Direct, develop, and maintain trusted relationships with regulatory, legislative, and other stakeholders.
 Expert witness for policy and financial matters to regulatory and legislative agencies.

Senior Manager of Finance and Regulatory Electric/Natural Gas Utilities
 Responsible for all forecasting and strategic planning aspects for Gas and Electric utilities and Non-Regulated companies, which requires positive working relationships with cross-functional teams.
 Part of the state-level executive leadership team; participate in operational initiatives – capital deployment, personnel plans, long-term strategic plans, and culture changes.
 Financial leader executing strategy for long-term success.  Strong partnerships with operations and other matrix teams to execute key strategies.

KYRA J. COYLE
Principal
Thoughtful Decision Making for Uncertain Times 2
 Financial modeling of purchase power agreements and strategic capital projects.  Financial team member in the divestiture of 49.9% interest in a non-regulated entity.  Lead, develop, and mentor coworkers.

Professional Finance Senior/Principal
 Responsible for budgeting, forecasting, and reporting for power generation assets. This included developing innovative ways to earn on PPAs and maximizing value by working with the operations team to maintain availability and reliability.
 Budget, forecast, and report on capital and O&M spending over $50M annually.  The key contact person for generation operations staff; helped educate the operations team on the optimal timing of associated expenditures and investments.
 Monitor and report to third-party owners on capital and O&M.

U.S Bentonite Processing, Inc.

Accounting Manager
 Led and supervised the accounting support staff, delegating duties and reviewing and approving invoices, payments, and other activities. Completed performance reviews and co-supervising the purchasing and logistics roles.
 Prepare and distribute financial statements to the board of directors monthly.  Responsible for closing, consolidation, and budgeting of three U.S.-based companies.  As the first point of contact during the annual audit, Ms. Coyle provided all the data needed and any adjustments made after the closing of the last period of the fiscal year.  Business SME for NetSuite. Responsible for creating a new chart of accounts, departments, and locations for three companies, training all software users, and answering questions.

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MCE Board of DirectorsJuly 17, 2025

MCE Board of Directors
July 17, 2025