Regulatory Packet — MCE Board of Directors, March 19, 2026 (part 2 of 2)

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

1. PG&E A.25-02-013 Expert testimony evaluating the
recovery of costs recorded to the
Portfolio Allocation Balancing
Account
California Public Utilities
Commission
California Community
Choice Association
2025

2. PG&E A.25-05-011 Expert testimony evaluating the
calculation of the Power Charge
Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
California Community
Choice Association
2025

3. SCE A.25-05-008 Expert testimony evaluating the
calculation of the Power Charge
Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
California Community
Choice Association
2025

4. PG&E
SCE
SDG&E
R.25-02-005 Rebuttal testimony addressing
resource adequacy market price
benchmark calculation for the
power charge indifference
adjustment
California Public Utilities
Commission
California Community
Choice Association
2025

5. PG&E
SCE
SDG&E
A.23-05-012
A.23-07-012
A.23-06-001
A.23-05-013
Expert testimony addressing
definition of fixed generation
costs and recovery from bundled
and unbundled customers
California Public Utilities
Commission
California Community
Choice Association, San
Diego Community Power,
Clean Energy Alliance
2024

6. PG&E A.24-05-009 Expert testimony evaluating the
calculation of the Power Charge
Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
California Community
Choice Association
2024

7. SCE A.24-05-007 Expert testimony evaluating the
calculation of the Power Charge
Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
California Community
Choice Association
2024

8. PG&E A.24-03-018 Expert testimony evaluating
allocation of generation benefits
during period of extended
operations at Diablo Canyon
Nuclear Power Plant
California Public Utilities
Commission
California Community
Choice Association
2024

Page 2 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

9. SCE A.23-06-001 Expert testimony evaluating the
calculation of the Power Charge
Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
California Community
Choice Association
2023

10. PG&E A.22-09-018 Expert testimony evaluating
customer benefits of a proposal
to transfer generation assets to a
newly created regulated utility
subsidiary
California Public Utilities
Commission
California Community
Choice Association
2023

11. PG&E R.23-01-007 Expert testimony proposing new
rate design and allocation of
generation benefits during period
of extended operations at Diablo
Canyon Nuclear Power Plant
California Public Utilities
Commission
California Community
Choice Association
2023

12. Joint IOUs R.22-07-005 Expert testimony addressing
inclusion of stranded costs in
newly proposed income
graduated fixed charges for
residential customers
California Public Utilities
Commission
California Community
Choice Association
2023

13. SCE A.12-01-008
A.12-04-020
A.14-01-007
Declaration supporting response
to petition for modification of
D.15-01-051, addressing changes
to optional green tariff program
rates
California Public Utilities
Commission
Clean Power Alliance,
California Choice Energy
Authority
2022

14. SCE A.22-05-014 Expert testimony evaluating the
calculation of the Power Charge
Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
Clean Power Alliance,
California Choice Energy
Authority, and Central
Coast Community Energy
2022

15. PG&E, SCE, SDG&E A.20-02-009
A.20-04-002
A.20-06-001
(Consolidated)
Expert testimony evaluating the
unrealized sales volumes and
revenue due to Public Safety
Power Shutoff events
California Public Utilities
Commission
CCA Parties (9 individual
CCAs)
2022

Page 3 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

16. San Diego Gas &
Electric
A.21-09-001 Expert testimony responding to
proposed residential
electrification tariff
California Public Utilities
Commission
San Diego Community
Power and Clean Energy
Alliance
2022

17. San Diego Gas &
Electric
R.20-05-003 Declaration supporting motion for
clarification of D.19-11-016,
quantifying impact to allocated
incremental reliability
procurement requirement due to
departing load
California Public Utilities
Commission
San Diego Community
Power
2021

18. Southern California
Edison
A.21-06-003 Expert testimony evaluating the
calculation of the Power Charge
Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
Clean Power Alliance and
California Choice Energy
Authority
2021

19. Pacific Gas & Electric A.21-06-001 Expert testimony evaluating the calculation of the Power Charge
Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
Joint Community Choice
Aggregators
2021

20. San Diego Gas &
Electric
A.21-04-010 Expert testimony evaluating the
calculation of the Power Charge
Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
San Diego Community
Power and Clean Energy
Alliance
2021

21. Pacific Gas & Electric A.12-01-008
A.12-04-020
A.14-01-007
Declaration supporting petition
for modification of D.15-01-051,
recommending changes to
optional green tariff program
rates designed to avoid shifting
costs of resource capacity to non-participants
California Public Utilities
Commission
Joint Community Choice
Aggregators
2021

22. Pacific Gas & Electric A.19-11-019 Expert testimony (adopted) addressing use of marginal costs
to determine economic
development rates and
responding to proposed
electrification tariff for retail
customers
California Public Utilities
Commission
Joint Community Choice
Aggregators
2021

Page 4 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

23. Pacific Gas & Electric A.20-07-002 Expert testimony evaluating the calculation of the Power Charge
Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
Joint Community Choice
Aggregators
2020

24. Southern California
Edison
A.20-07-004 Expert testimony evaluating the
calculation of the Power Charge
Indifference Amount charged to
Community Choice Aggregators
California Public Utilities
Commission
Clean Power Alliance and
California Choice Energy
Authority
2020

25. Pacific Power Docket UE 375 Joint testimony supporting a settlement agreement resolving
the annual variable power supply
cost forecast and generation
resource dispatch model
Public Utility Commission of
Oregon
Facebook, Inc. 2020

26. Pacific Gas & Electric A.20-02-009 Expert testimony evaluating the appropriateness of entries
recorded to the Portfolio
Allocation Balancing Account to
true up the Power Charge
Indifference Amount
California Public Utilities
Commission
Joint Community Choice
Aggregators
2020

27. Vectren Energy Delivery
of Indiana
Cause No. 43354 MCRA
21 S1
Expert testimony supporting a
settlement agreement regarding
the calculation and use of a 4CP
load study to allocate tariff rider
costs among customer classes
Indiana Utility Regulatory
Commission
SABIC Innovative Plastics
Mt. Vernon, LLC
2020

28. PacifiCorp Docket UE 307 Expert testimony supporting the annual variable power supply cost
forecast and generation resource
dispatch model
Public Utility Commission of
Oregon
2016

29. PacifiCorp Docket UM 1662 Joint testimony with Portland General Electric regarding the
need for a renewable resource
tracking mechanism to provide
cost recovery related to the
impacts of renewable resource
generation
Public Utility Commission of
Oregon
2015

Page 5 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

30. PacifiCorp Docket UE 296 Expert testimony supporting the annual variable power supply cost
forecast and generation resource
dispatch model
Public Utility Commission of
Oregon
2015

31. PacifiCorp Docket No. 20000-469-
ER-15
Expert testimony regarding the
annual variable power supply cost
forecast and modifications to the
Energy Cost Adjustment
Mechanism
Public Service Commission
of Wyoming
2015

32. PacifiCorp Docket No. 15-035-03 Provided expert testimony regarding the true up of variable
power supply costs in the Energy
Balancing Account mechanism
Public Service Commission
of Utah
2015

33. PacifiCorp Docket UM 1716 Expert testimony proposing changes to the calculation of
PURPA avoided costs for large
resources
Public Utility Commission of
Oregon
2015

34. PacifiCorp Docket No. 20000-481-
EA-15
Expert testimony proposing
changes to the calculation of
PURPA avoided costs for large
resources
Public Service Commission
of Wyoming
2015

35. PacifiCorp Docket No. 15-035-T06 Expert testimony updating standard PURPA avoided cost
prices and supporting
modifications to the avoided cost
calculation for small resources
Public Service Commission
of Utah
2015

36. PacifiCorp Case No. PAC-E-15-03 Expert testimony proposing changes to the calculation of
PURPA avoided costs for large
resource
Idaho Public Utilities
Commission
2015

Page 6 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

37. PacifiCorp Docket UE-144160 Declaration supporting updates to standard PURPA avoided cost
prices and supporting
modifications to the avoided cost
calculation for small resources
Washington Utilities and
Transportation Commission
2014

38. PacifiCorp Docket UE 287 Expert testimony supporting the annual variable power supply cost
forecast and generation resource
dispatch model
Public Utility Commission of
Oregon
2014

39. PacifiCorp Case No. PAC-E-14-01 Expert testimony regarding the true up of variable power supply
costs in the Energy Cost
Adjustment Mechanism
Idaho Public Utilities
Commission
2014

40. PacifiCorp Docket A.14-08-002 Expert testimony supporting the annual variable power supply cost
forecast and the true up of costs
in the Energy Cost Adjustment
Clause mechanism
California Public Utilities
Commission
2014

41. PacifiCorp Docket No. 20000-447-
EA-14
Expert testimony regarding the
true up of annual variable power
supply cost in the Energy Cost
Adjustment Mechanism
Public Service Commission
of Wyoming
2014

42. PacifiCorp Docket No. 14-035-31 Expert testimony regarding the true up of variable power supply
costs in the Energy Balancing
Account mechanism
Public Service Commission
of Utah
2014

43. PacifiCorp Case No. PAC-E-13-03 Expert testimony regarding the true up of variable power supply
costs in the Energy Cost
Adjustment Mechanism
Idaho Public Utilities
Commission
2013

Page 7 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

44. PacifiCorp Docket A.13-08-001 Expert testimony supporting the annual variable power supply cost
forecast and the true up of costs
in the Energy Cost Adjustment
Clause mechanism
California Public Utilities
Commission
2013

45. PacifiCorp Docket No. 13-035-32 Expert testimony regarding the true up of variable power supply
costs in the Energy Balancing
Account mechanism
Public Service Commission
of Utah
2013

46. PacifiCorp Docket UM 1610 Expert testimony proposing changes to the calculation of
PURPA avoided costs for large and
small generation resources
Public Utility Commission of
Oregon
2012

47. PacifiCorp Docket A.12-08-003 Expert testimony supporting the annual variable power supply cost
forecast and the true up of costs
in the Energy Cost Adjustment
Clause mechanism
California Public Utilities
Commission
2012

48. PacifiCorp Docket No. 12-035-67 Expert testimony regarding the true up of variable power supply
costs in the Energy Balancing
Account mechanism
Public Service Commission
of Utah
2012

49. PacifiCorp Docket No. 20000-389-
EP-11
Expert testimony regarding the
collection of deferred balances
accrued through previous Power
Cost Adjustment Mechanisms
Public Service Commission
of Wyoming
2011

50. PacifiCorp Docket No. 20000-405-
ER-11
Inter-jurisdictional cost allocation
and revenue requirement and
sponsored expert testimony in
corresponding general rate case
Public Service Commission
of Wyoming
2011

51. PacifiCorp Case No. GNR-E-11-03 Expert testimony proposing changes to the calculation of
PURPA avoided costs for large and
small generation resources
Idaho Public Utilities
Commission
2011

Page 8 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

52. PacifiCorp Case No. PAC-E-06-10 Expert testimony regarding low-income customer weatherization rebates
Idaho Public Utilities
Commission
2010

53. PacifiCorp Docket No. 20000-405-
ER-10
Inter-jurisdictional cost allocation
and revenue requirement and
sponsored expert testimony in
corresponding general rate case
Public Service Commission
of Wyoming
2010

54. PacifiCorp Docket No. 10-035-89 Inter-jurisdictional cost allocation and revenue requirement and
sponsored expert testimony in
corresponding general rate case
Public Service Commission
of Utah
2010

55. PacifiCorp Docket No. 20000-352-
ER-09
Inter-jurisdictional cost allocation
and revenue requirement and
sponsored expert testimony in
corresponding general rate case
Public Service Commission
of Wyoming
2009

56. PacifiCorp Case No. PAC-E-08-07 Inter-jurisdictional cost allocation and revenue requirement and
sponsored expert testimony in
corresponding general rate case
Idaho Public Utilities
Commission
2008

57. PacifiCorp Docket No. 20000-333-
ER-08
Inter-jurisdictional cost allocation
and revenue requirement and
sponsored expert testimony in
corresponding general rate case
Public Service Commission
of Wyoming
2008

ATTACHMENT C
Select Discovery Responses
ERRAandPCIA-Policies-UpdateReformOIR_DR_CalCCA_003-Q004 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
ERRA and PCIA Policies – Update and Reform OIR
Rulemaking 25-02-005
Data Response
PG&E Data Request No.: CalCCA_003-Q004
PG&E File Name: ERRAandPCIA-Policies-UpdateReformOIR_DR_CalCCA_003-Q004 Request Date: February 2, 2026
Requester DR No.: 003
Requesting Party: California Community Choice Association Requester: Tim Lindl
Date Sent: February 17, 2026
PG&E Witness(es): Christa Hoffman and Angelia Vega – Energy Policy and Procurement QUESTION 004
For any year during which PG&E’s banked RECs have been counted and valued as Retained RPS for purposes of the PCIA, please respond to the following:
a. Quantify the banked RECs used by year.
b. Identify original generation year for the banked RECs that have been counted as Retained RPS in the PCIA annually.
c. Identify the price used to value the banked RECs, and the total value credited to the PCIA annually.

ANSWER 004
PG&E clarifies that actual RECs generated prior to 2019 were not categorized as “Retained RPS” for PCIA ratemaking purposes. Instead, for PCIA ratemaking, the value of RECs that were “forecast to be generated, net of sales” in PG&E’s ERRA Forecast proceedings from 2013 through 2018 were valued in the indifference calculations based on the vintaged MPBs using the methodology approved in D.06-07-030, as modified by D.11-12-018, and Resolution E-4475. Given that the pre-2019 PCIA rate was not trued-up for actual generation, there will be differences in the generation volumes reflected in Annual RPS Compliance Reports and minimum retained generation tables, compared to the forecast RPS generation used for PCIA rate setting in those years. a. PG&E refers CalCCA to PG&E’s response to Question 1.a which summarizes the quantity of RECs used towards the minimum retained RPS requirement.

PG&E refers CalCCA to PG&E’s response in Question 1.a which includes the delivery year of RECs used towards the minimum retained RPS requirement, by year.

Prior to 2019, the PCIA rate was set based on a forecast of RECs that were expected to be generated, net of sales, and those RECs were valued only in the indifference calculation, which was used to set PCIA rates.

ERRAandPCIA-Policies-UpdateReformOIR_DR_CalCCA_003-Q004 Page 2 These forecast of RECs were never categorized as “Retained RPS” in the ERRA Forecast proceedings, prior to 2019.
b. Banked RECs were presented and verified in the RPS Plan Rulemaking dockets. The final amounts to be counted Retained RECs were determined through the Final Verified RPS Compliance Period Report submitted to the Commission, after the compliance period that RECs had been verified by the California Energy Commission.

Prior to 2020, actual retained RECs determined through RPS Compliance Reports were never presented or used in the ERRA Forecast Proceedings to determine PCIA rates.

Pre-2019 REC Forecast for PCIA Ratemaking
For the Pre-2019 period, only a forecast of RECs from the PCIA-eligible portfolio were valued when determining the indifference amount, for each cumulative vintage PCIA-eligible portfolio.

The REC Benchmark applicable for the years 2013 – 2018 are shown on line 8 in the table below.

The REC value credited in the indifference amount was embedded in the total portfolio MPBs, that are calculated for each vintage portfolio. Thus, there is not a single line-item value in the Pre-2019 PCIA workpapers that reflects just the REC valuation.

To illustrate how the PCIA MPBs and indifference calculations were presented in years prior to 2019, the tables below show PG&E’s 2016 November Update indifference calculations. Table 9-3 below shows the derivation of the vintage MPBs and an RPS premium in each vintage MPB is presented on lines 15 - 26. This presentation aligns with the requirements in Resolution E-4475, Attachment A.

The RPS inputs on lines 21 and 22 for the IOUs’ RPS Adders are weighed at 68 percent and the DOE REC value is weighed at 32 percent. The weighted average renewable premium (line 23, in Table 9-3) is then weighted based on percentage of renewable generation in the portfolio and then added to the brown power MPB and the capacity MPB to determine a MPB for each cumulative vintage total portfolio. Table 9-2, below, shows the application of the vintage portfolio’s MPBs in the indifference calculation.

Line No. Description 2013 2014 2015 2016 2017 2018
1 IOU Green - ERRA Forecast - provided by ED 119.95 128.09 118.43 92.13 73.92 61.47 2 less Load Wt. Energy - PG&E Forecast (at GenMeter) 38.93 39.05 41.25 32.9 35.22 33.77 3 =l.1- l.2 IOU RPS Green Adder 81.02 89.04 77.18 59.23 38.70 27.70 4 DOE WECC Survey - Adder - Compliance AL by IOUs 15.870 16.450 16.280 16.550 16.640 16.640 5 = l.3 x .68 IOU RPS Green @ 68% 55.09 60.55 52.48 40.28 26.32 18.84 6 = l.4 x .32 DOE @ 32% 5.08 5.26 5.21 5.30 5.32 5.32
7 - l.5 + l.6 ERRA Forecast Green Adder @ Generator Meter 60.17 65.81 57.69 45.57 31.64 24.16 8 = l.7 x 1.06 ERRA Forecast Green Adder @ Customer Meter (w/ lline loss) 63.78 69.76 61.15 48.31 33.54 25.61 9 = l.2 x 1.06 ERRA Forecast - Brown Power @ Customer Meter (w/ line loss) 41.27 41.39 43.73 34.87 37.33 35.80 PG&E
ERRA
Forecast -
November
Updates
ERRAandPCIA-Policies-UpdateReformOIR_DR_CalCCA_003-Q004 Page 3 Actual REC Value Supporting Recorded Entries to ERRA for 2019 - 2025 For the period 2019 – 2025, the Retained RECs were recorded to the ERRA and the entries in the balancing account, including any adjusting entries made in October to reflect the Final REC MPB issued by the Commission’s Energy Division in the Fall, would be reflected in the ERRA line item dedicated to showing the costs for retained RECs for the record period. The Final REC MPBs for the period 2019 – 2025 are shown below:

RPS MPB
($/MWh) 2019 2020 2021 2022 2023 2024 2025
Final MPB 16.44 15.10 14.23 13.24 30.30 54.56 63.86
PG&E has not provided the actual values recorded to ERRA for Retained RPS values for the period 2019 - 2025 but can provide this information in a supplemental response to this data request.

TABLE 9-3

PACIFIC GAS AND ELECTRIC COMPANY
2016 VINTAGED MARKET PRICE BENCHMARK
2016
Line
No. Description
Portfolio TBCC
Adders
2009
Vintage
2010
Vintage
2011
Vintage
2012
Vintage
2013
Vintage
2014
Vintage
2015
Vintage
2016
Vintage
1 Forward Price Location: NP 15
2 Average Prices from October Postings
3 On Peak $ 35.77 $ 35.77 $ 35.77 $ 35.77 $ 35.77 $ 35.77 $ 35.77 $ 35.77 $ 35.77 4 Off Peak $ 28.27 $ 28.27 $ 28.27 $ 28.27 $ 28.27 $ 28.27 $ 28.27 $ 28.27 $ 28.27 5 Publication: Platts ICE
6 On-Peak Weighting 61.7% 61.7% 61.7% 61.7% 61.7% 61.7% 61.7% 61.7% 61.7% 7 Off-Peak Weighting 38.3% 38.3% 38.3% 38.3% 38.3% 38.3% 38.3% 38.3% 38.3% 8 9 Calculated Baseload Price $ 32.90 $ 32.90 $ 32.90 $ 32.90 $ 32.90 $ 32.90 $ 32.90 $ 32.90 $ 32.90 10 Capacity Adder TBCC $ 12.87 $ 8.89 12.49 12.27 12.26 12.15 12.87 12.89 12.88 12.88 11 Subtotal Before Line Loss 41.79 45.39 45.17 45.15 45.05 45.77 45.79 45.78 45.78 12 Line Loss 1.060 1.060 1.060 1.060 1.060 1.060 1.060 1.060 1.060 13 Brown Market Price Benchmark, by Vintage $ 44.29 $ 48.11 $ 47.88 $ 47.86 $ 47.75 $ 48.51 $ 48.54 $ 48.52 $ 48.52 14 15 Renewable Premium
16 Green Benchmark ‒ Energy Division $ 92.13
17 Less Brown Power BM (No Capacity Value, See Line 11) $ 32.90 18 IOU RPS Premium $ 59.23
19 20 Weighting for RPS Adder
21 IOU 2015 RPS Premium, Delivered Energy @ 68% 40.28 $ $ 40.28 $ 40.28 $ 40.28 $ 40.28 $ 40.28 $ 40.28 $ 40.28 $ 40.28 $ 40.28 22 DOE REC Value $16.55/MWh @ 32% 5.30 5.30 $ 5.30 $ 5.30 $ 5.30 $ 5.30 $ 5.30 $ 5.30 $ 5.30 $ 5.30 23 Weighted Average Renewable Premium $ 45.57 $ 45.57 $ 45.57 $ 45.57 $ 45.57 $ 45.57 $ 45.57 $ 45.57 $ 45.57 $ 45.57 24 25 Renewable Percentage in Portfolio 30.4% 34.4% 28.1% 34.1% 35.47% 36.5% 36.9% 36.9% 36.9% 36.9% 26 Renewable Adder, by Vintage TBCC $ 13.87 $ 15.68 $ 12.81 $ 15.54 $ 16.17 $ 16.62 $ 16.81 $ 16.80 $ 16.83 $ 16.83 27 28 MPB at Generator With Renewable Premium, by Vintage 57.47 58.20 60.71 61.32 61.66 62.57 62.59 62.61 62.61 29 Line Loss 1.060 1.060 1.060 1.060 1.060 1.060 1.060 1.060 1.060 30 MPB With Renewable Premium, by Vintage $ 60.92 $ 61.69 $ 64.35 $ 65.00 $ 65.36 $ 66.33 $ 66.34 $ 66.36 $ 66.36 Ongoing
CTC
PCIA
ERRAandPCIA-Policies-UpdateReformOIR_DR_CalCCA_003-Q004 Page 4 The total market value credited to the cumulative 2015 vintage portfolio was $3.988 Billion. To determine the imputed value for RPS generation in PG&E’s 2015 vintage total portfolio, one could multiply the Green Adder Premium presented in the Table included in response to Q.3.b ($48.31/MWh) by 36.9 percent of the 2015 vintage portfolio energy of 60,098 GWh. The imputed value of the RECs in the PCIA-eligible portfolio in 2015 would have been equal to $48.31/MWh x 60,098 x 36.9 = $1.071 billion.

PG&E’s annual ERRA Forecast November/Fall Updates and respective Commission decisions are listed below. The relevant proceeding documents and associated decisions can be found on the Commission’s Documents page at the following link: https://apps.cpuc.ca.gov/apex/f?p=401:1:0 Year ERRA Forecast
Application
ERRA Forecast
Decisions
2013 A.12-06-002 D.12-12-008
2014 A.13-05-015 D.13-12-043
2015 A.14-05-024 D.14-12-053
2016 A.15-06-001 D.15-12-022
2017 A.16-06-003 D.16-12-038
2018 A.17-06-005 D.18-01-009
ERRAandPCIA-Policies-UpdateReformOIR_DR_CalCCA_003-Q005 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
ERRA and PCIA Policies – Update and Reform OIR
Rulemaking 25-02-005
Data Response
PG&E Data Request No.: CalCCA_003-Q005
PG&E File Name: ERRAandPCIA-Policies-UpdateReformOIR_DR_CalCCA_003-Q005 Request Date: February 2, 2026
Requester DR No.: 003
Requesting Party: California Community Choice Association Requester: Tim Lindl
Date Sent: February 17, 2026
PG&E Witness(es): Christa Hoffman – Energy Policy and Procurement QUESTION 005
Regarding the function of the PCIA and bundled generation rates before 2019:
a. Confirm that the forecasted indifference amount calculated each year included a credit for the value of RECs generated during the year, valued at the then-current RPS market price benchmark. If not confirmed, please explain. b. Confirm that the indifference amount credit described in part a was shared between departed load and bundled customers, as constituted at the time rates are set. If not confirmed, please explain.
c. Confirm that bundled customers' generation rates included the market cost of RECs, the opposite of the REC credit included in the indifference amount. If not confirmed, please explain.

ANSWER 005
a. Not confirmed. Prior to 2019, the forecasted indifference amount was based on forecasted RECs to be generated during the year. The value of the renewable attributes in PG&E’s PCIA-eligible total portfolio indifference calculation was included in the vintage specific market price benchmark that was established for the forecast year. See Resolution E-4475, Appendix A, which provides a formula for determining the MPB for vintage portfolios v, in year n, where n = the forecast year covered in the calculation and v = PCIA vintage year. Resolution E-4475 can be found at the following link:
https://docs.cpuc.ca.gov/PublishedDocs/WORD_PDF/FINAL_RESOLUTION/ 166454.PDF
b. Not confirmed. The calculation of the total portfolio indifference amount did not allocate the total portfolio costs or market value to bundled and non-exempt departing load customers as part of the steps to calculate the indifference amount. The total portfolio indifference calculation was calculated at the cumulative vintage portfolio level, for each vintage. It was not practical nor required that the individual portfolio costs and portfolio ERRAandPCIA-Policies-UpdateReformOIR_DR_CalCCA_003-Q005 Page 2 market value be allocated load prior to determining the indifference amount used to set vintaged PCIA rates.

See D.06-07-030, as modified by as modified by D.07-01-030, and D.17-08-026.

Links to these decisions are included below:

D.06-07-030:
https://docs.cpuc.ca.gov/PublishedDocs/WORD_PDF/FINAL_DECISION/58302.

PDF
D.07-01-030:
https://docs.cpuc.ca.gov/PublishedDocs/WORD_PDF/FINAL_DECISION/64048.

PDF
D.17-08-026:
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M195/K123/195123481 .pdf
See also D.08-09-012 and associated appendices, which reaffirmed the D.06-07- 030 Total Portfolio Indifference calculation methodology would apply to new generation resources on a vintage basis.

D.08-09-012:
https://docs.cpuc.ca.gov/PublishedDocs/WORD_PDF/FINAL_DECISION/87615.

PDF
Appendix
D: https://docs.cpuc.ca.gov/PublishedDocs/WORD_PDF/FINAL_DECISION/876

17.PDF
Appendix
E: https://docs.cpuc.ca.gov/PublishedDocs/PUBLISHED/GRAPHICS/87618.PDF c. Not confirmed. There was no explicit line item in the ERRA Forecast for an MPB-based market value.

Prior to 2019, bundled customer’s generation revenue requirement and rates were set based on the total portfolio resource forecast that would be recorded to the ERRA balancing account, net of PCIA revenues that were forecast to be received from non-exempt departing load based on the CPUC required templates for calculating forecast PCIA revenue requirements and rates, plus amortization of the ERRA balancing account balance. That is, the PCIA revenues were a line item forecast credit in the ERRA revenue requirement determination.

ERRAandPCIA-Policies-UpdateReformOIR_DR_CalCCA_003-Q009 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
ERRA and PCIA Policies – Update and Reform OIR
Rulemaking 25-02-005
Data Response
PG&E Data Request No.: CalCCA_003-Q009
PG&E File Name: ERRAandPCIA-Policies-UpdateReformOIR_DR_CalCCA_003-Q009 Request Date: February 2, 2026
Requester DR No.: 003
Requesting Party: California Community Choice Association Requester: Tim Lindl
Date Sent: February 17, 2026
PG&E Witness(es): Christa Hoffman – Energy Policy and Procurement QUESTION 009
Assume PG&E’s REC bank contains RECs generated and banked from the same RPS-eligible resource prior to 2019 as well as in 2019 or later. For purposes of RPS compliance, is there any difference between the RECs banked prior to 2019 versus the RECs banked in 2019 and later? Please explain.

ANSWER 009
While in RPS compliance there is not a distinction between RECs generated before or after 2019, there is a significant difference between these RECs when valued for ratemaking purposes due to changes in revenue requirements and ratemaking adopted by D.18-10-019 and D.19-10-001.

ERRAandPCIA-Policies-UpdateReformOIR_DR_CalCCA_003-Q014 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
ERRA and PCIA Policies – Update and Reform OIR
Rulemaking 25-02-005
Data Response
PG&E Data Request No.: CalCCA_003-Q014
PG&E File Name: ERRAandPCIA-Policies-UpdateReformOIR_DR_CalCCA_003-Q014 Request Date: February 2, 2026
Requester DR No.: 003
Requesting Party: California Community Choice Association Requester: Tim Lindl
Date Sent: February 20, 2026
PG&E Witness(es): Donna Barry – Energy Policy and Procurement QUESTION 014
Please provide the proportion of PG&E’s customers who have received bundled service for every year from 2011 through 2025.

ANSWER 014
The bundled customer percentage as a percent of all PCIA non-exempt customers is shown in the table below:

Rate Effective
System Total for
Bundled, DA, CCA
Bundled Pre-2009 DA
Post-2008
DA/CCA
2011 100% 90.1% 6.2% 3.7%
2012 100% 89.5% 6.4% 4.2%
2013 100% 88.0% 5.9% 6.1%
2014 100% 87.9% 5.9% 6.2%
2015 100% 91.9% 8.1%
2016 100% 89.6% 10.4%
2017 100% 84.9% 15.1%
2018 100% 65.7% 34.3%
2019 92% 47.2% 45.2%
2020 100% 48.7% 51.3%
2021 100% 44.4% 55.6%
2022 100% 40.0% 60.0%
2023 100% 42.4% 57.6%
2024 100% 40.7% 59.3%
2025 100% 36.9% 63.1%
Percent of VPCIA Non-Exempt Load
Southern California Edison
R.25-02-005 – OIR to Consider ERRA and PCIA Rules and Processes

DATA REQUEST SET C a l C C A - S C E - 0 0 3
To: CalCCA
Prepared by: Eric Lee
Job Title: Sr. Advisor
Received Date: 2/2/2026
Response Date: 2/17/2026
Question 3.7:

If SCE’s available RPS-eligible generation during an RPS compliance period is less than its RPS requirement for that period, does SCE agree it must meet its RPS compliance obligation by using banked RECs, procuring RECs, or procuring additional RPS-eligible generation? If no, please explain.

Response to Question 3.7:

Generally, yes.

Southern California Edison
R.25-02-005 – OIR to Consider ERRA and PCIA Rules and Processes

DATA REQUEST SET C a l C C A - S C E - 0 0 3
To: CalCCA
Prepared by: Eric Lee
Job Title: Sr. Advisor
Received Date: 2/2/2026
Response Date: 2/17/2026
Question 3.9:

Assume SCE’s REC bank contains RECs generated and banked from the same RPS-eligible resource prior to 2019 as well as in 2019 or later. For purposes of RPS compliance, is there any difference between the RECs banked prior to 2019 versus the RECs banked in 2019 and later? Please explain.

Response to Question 3.9:

For RPS compliance purposes, there is no difference between RECs banked prior to 2019 and those banked in 2019 or later, provided they meet standard RPS eligibility. Both types of banked RECs may be used to satisfy SCE’s RPS obligations.

However, there are important differences from a ratemaking perspective. Under the current PCIA methodology, RECs generated and banked on and after January 1, 2019 have a zero-dollar value applied in the year they are generated. The RPS MPB is only applied if and when those banked RECs are used for bundled compliance. There is then a crediting and debiting methodology that applies specifically to Retained RPS across the ERRA BA and the PABA. Under the prior PCIA methodology, there was no concept of valuing banked RECs based on how or when they were used.

Instead, a market value for renewable energy was calculated each year using a forecast volume of renewable energy to be generated in the given year multiplied by an administratively-set weighted average renewable benchmark. That calculated market value was then added to the other forecast value amounts and subtracted from the PCIA-eligible resource and contract costs to set a composite PCIA rate for that year. Any differences between the forecast and actual amounts and costs resulted in over- or under-collections in the ERRA BA that remained solely with bundled service customers.

Additionally, there is a 36-month rolling timeframe where RECs that have been generated can still be sold/transferred to third-parties. Once that time has passed and the REC is banked (retired in WREGIS), the RECs can only be used for SCE’s compliance requirements and cannot be transferred to third parties.

Southern California Edison
R.25-02-005 – OIR to Consider ERRA and PCIA Rules and Processes

DATA REQUEST SET C a l C C A - S C E - 0 0 3
To: CalCCA
Prepared by: Eric Lee
Job Title: Sr. Advisor
Received Date: 2/2/2026
Response Date: 2/17/2026
Question 3.14:

Please provide the proportion of SCE’s customers who have received bundled service for every year from 2011 through 2025.

Response to Question 3.14:

See attached Excel spreadsheet, titled “Response to CalCCA Q3.14.xlsx” for the proportion of SCE’s customers who have received bundled service for every year from 2012 through 2025. SCE is unable to provide data for 2011 due to verification issues.

Response to CalCCA Q3.14.xlsx
SCE Customers 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Bundled 4,952,530 4,979,877 5,008,690 4,986,834 5,010,532 5,001,107 4,980,153 4,081,679 3,869,492 3,896,477 3,662,958 3,679,390 3,747,609 3,765,408 Unbundled 30,199 29,866 29,047 80,516 78,631 119,624 179,749 1,114,558 1,360,880 1,321,852 1,596,274 1,616,164 1,585,283 1,621,561 Total Customers 4,982,729 5,009,743 5,037,737 5,067,350 5,089,163 5,120,731 5,159,902 5,196,237 5,230,372 5,218,329 5,259,232 5,295,554 5,332,892 5,386,969 Percent Bundled 99% 99% 99% 98% 98% 98% 97% 79% 74% 75% 70% 69% 70% 70% Percent Unbundled 1% 1% 1% 2% 2% 2% 3% 21% 26% 25% 30% 31% 30% 30% Notes

1. 2011 data is not available as SCE was unable to verify the data from that year.

2. SCE implemented its Customer Service Re-Platform (CSRP) system in March/April 2021. Prior to CSRP, streetlights had an account per streetlight. Post-CSRP, an entire string of streetlights would be on a single account. This resulted in a decrease to the total number of customers.

3. In June 2021, a CCA, Western Community Energy (WCE), failed and reverted all 113,000 WCE customers back to SCE. This resulted in a net decrease to the unbundled customer percentage for 2021 when compared to the previous year.

4. Reversion of approximately 65,000 customers from Orange County Power Authority (OCPA) in 2024 also resulted in a net decrease of unbundled customers.

Year
ERRA/PCIA Reform (R.25-02-005) Data Request
California Community Choice Association (CalCCA)
CalCCA-SDGE-DR-003
DATE RECEIVED: February 2, 2026
DATE DUE: February 17, 2026
______________________________________________________________________________ 15 QUESTION 3.14
Please provide the proportion of SDG&E’s customers who have received bundled service for every year from 2011 through 2025.

SDG&E Response:

SDG&E objects to this request on the grounds that it seeks information that is not reasonably calculated to lead to the discovery of admissible evidence. Subject to and without waiving the foregoing objections, SDG&E responds as follows:

Please refer to the attached excel file “PUBLIC_CalCCA_DR-003_Q 3.14.xlsx”.

PUBLIC_CalCCA_DR-003_Q 3.14.xlsx
SDG&E - PCIA Reform Track 2
CalCCA 3rd DR, Q3.14
MWh usage over each year
Bundled customers Direct Access CCA Total Percent
bundled Percent unbundled
2011 16,249,031 - 3,265,472 19,514,503 83% 17%
2012 16,626,721 - 3,398,978 20,025,699 83% 17%
2013 16,164,015 - 3,592,677 19,756,692 82% 18%
2014 16,467,854 - 3,648,099 20,115,954 82% 18%
2015 16,266,949 - 3,651,846 19,918,795 82% 18%
2016 15,653,136 - 3,515,568 19,168,704 82% 18%
2017 15,623,204 - 3,393,906 19,017,111 82% 18%
2018 15,139,149 3,593,995 33,704 18,766,848 81% 19%
2019 14,405,887 3,487,355 61,318 17,954,559 80% 20%
2020 14,398,202 3,424,013 57,771 17,879,986 81% 19%
2021 11,898,924 3,570,714 1,899,782 17,369,420 69% 31%
2022 7,800,107 3,840,740 6,059,056 17,699,903 44% 56%
2023 4,619,558 3,917,877 8,309,914 16,847,349 27% 73%
2024 3,207,210 3,961,841 9,522,238 16,691,289 19% 81%
2025 2,884,273 3,991,384 9,912,807 16,788,465 17% 83%

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Improve
the California Climate Credit.

R.25-07-013
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S OPENING COMMENTS ON ASSIGNED COMMISSIONER’S SCOPING MEMO AND RULING
Leanne Bober,
Director of Regulatory Affairs and
Deputy General Counsel
Kevin Johnston,
Regulatory Counsel

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
1121 L Street, Suite 400
Sacramento, CA 95814
Telephone: (510) 980-9459
E-mail: [email protected]
March 2, 2026
i

TABLE OF CONTENTS
I. INTRODUCTION ...............................................................................................................1 II. SHORT-TERM SPECULATIVE CLIMATE CREDIT CHANGES MAY

NOT IMPROVE AFFORDABILITY AND SHOULD BE POSTPONED
PENDING ADEQUATE ANALYSIS AND RECORD DEVELOPMENT .......................3 A. Changing the Climate Credit Timing Based on Presumptions of “High-Billed Months” Without any Analysis of Impacts Should be Rejected ...................4 B. Proposed Interim Changes to the Climate Credit Fail to Consider Increased Administrative Costs and Operational Inefficiencies ..............................5 C. The Proposed Timing Changes to Distribution of the Climate Credit Fail to Address the Time Value of Money ...............................................................5 D. The Proposed Changes Fail to Consider Customer Expectations of the Climate Credit’s Distribution ...................................................................................6 E. Customer Confusion and Inaccurate Messaging Outweigh Any Perceived Benefits of Interim Changes to the Climate Credit and Necessitate Future CCA Involvement ...................................................6

1. Risks of Customer Confusion Must be Mitigated in any Change to the Climate Credit .......................................................................7

2. Climate Credit Communications Must be Neutral to Prevent CCA Customer Confusion ...........................................................................8 III. INSTEAD OF RUSHING TO CHANGE THE CLIMATE CREDIT ON AN

INTERIM BASIS, THE COMMISSION SHOULD REVISIT THE

CLIMATE CREDIT POLICY OBJECTIVES AND PRIORITIES AND

MAKE DECISIONS BASED ON IN-DEPTH ANALYSIS AND A
COMPLETE RECORD .......................................................................................................9 A. The Commission Should Revisit the Climate Credit Objectives and Priorities Prior to Any Changes to the Climate Credit ............................................9 B. A Data-Driven Process and Full Evidentiary Record Should be Developed Prior to Any Changes to the Climate Credit ........................................10 IV. CALCCA’S RESPONSES TO SECTION 4.2 OF THE SCOPING RULING .................11

1. What immediate changes can be made to the residential electric and gas Climate Credit in the near term to improve its affordability impact while this proceeding considers broader, permanent changes to Climate Credit methodologies, eligibility, distribution, and other factors? ...................................11 Table of Contents continued
ii

2. Current timing of the residential Climate Credit is based on a basic assumption that spring and fall are relatively low energy usage seasons, and that awareness of the credit would be maximized if delivered at this time; the primary objective has not been focused on affordability impacts. Given the Legislature’s mandate to maximize affordability, should the Commission order the utilities to move up the fall 2026 electric residential Climate Credit, delivering it instead as a summer Climate Credit in August or September 2026? ........................................11

3. If the Commission approves the pause in the distribution of the residential electric 2026 Climate Credit, should it order the spring credit to instead be delivered in summer 2026 as well? Since Climate Credit amounts are set, should the two 2026 credits be delivered in August and September, respectively? ....................................................................11

4. Would it benefit customer affordability for the Commission to order the spring 2027 gas Climate Credit to instead be delivered as a winter credit in February 2027? ........................................................................................11

5. Should the Commission order any other changes to the residential Climate Credit to maximize affordability that can take effect in 2026? ................12

7. Should Phase 1A changes be explicitly designated as interim, applicable only until the resolution of Phase 1B and without prejudice to any of the broader changes being considered in that phase? .............................12

8. What specific direction and authority do the utilities need to implement the immediate affordability actions approved in Phase 1A? ...............12

9. What outreach changes are possible for Phase 1A immediate affordability actions? Should the Commission require messaging delivered in 2026 to refer to the Cap-and-Invest Program? ...................................12

10. What direction must the Commission give to ensure compliance with Pub.

Util. Code Section 748.5 (b)(2), regarding updates to the customer outreach plan? ........................................................................................................12

11. What direction do the utilities need to effectuate the transfer of 5% of revenues to the State Treasury for deposit in the California Transmission Accelerator Revolving Fund pursuant to Pub. Util. Code Section 748.5(d)? What documentation should the Utilities provide to the Commission demonstrating their transmittal of the funds annually? Overall, what action must the Commission take to ensure compliance with this code section? ............13 V. CONCLUSION ..................................................................................................................13 iii
SUMMARY OF RECOMMENDATIONS1
CalCCA recommends the following in response to the Phase 1A questions in the Scoping Ruling:
• Immediate modifications to the Climate Credit for 2026 and 2027 are premature and should be postponed given risks of increasing administrative costs, reducing net affordability benefits, and potential customer confusion; • The Commission must ensure clear and accurate customer communications regarding any Climate Credit changes, with CCAs meaningfully involved in developing and reviewing messaging to avoid customer confusion and ensure neutrality; and
• Prior to implementing Climate Credit changes, the Commission should reevaluate its Climate Credit objectives and priorities, and only base decisions on an in-depth analysis and a full evidentiary record.
1 Acronyms used herein are defined in the body of this document.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Improve
the California Climate Credit.

R.25-07-013
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S OPENING COMMENTS ON ASSIGNED COMMISSIONER’S SCOPING MEMO AND RULING
California Community Choice Association2(CalCCA) submits these opening comments pursuant to the Assigned Commissioner’s Scoping Memo and Ruling3(Scoping Ruling), dated February 3, 2026. The Scoping Ruling directs the investor-owned utilities (IOU), and authorizes other parties to file comments responding to the questions in Section 4.2 of the Scoping Ruling regarding proposed immediate changes to the residential Climate Credit.

I. INTRODUCTION
California is facing a profound and well-documented affordability crisis. As highlighted in Governor Gavin Newsom’s 2024 Executive Order N-5-24, the State has recognized the urgent need for remedies, including “maximizing” the Climate Credit. 4 That urgency is now being
echoed nationally, with California “having the highest cost of living in the nation” with prices 2 California Community Choice Association represents the interests of 24 community choice electricity providers in California: Apple Valley Choice Energy, Ava Community Energy, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance of Southern California, CleanPowerSF, Desert Community Energy, Energy For Palmdale’s Independent Choice, Lancaster Energy, Marin Clean Energy, Orange County Power Authority, Peninsula Clean Energy, Pico Rivera Innovative Municipal Energy, Pioneer Community Energy, Pomona Choice Energy, Rancho Mirage Energy Authority, Redwood Coast Energy Authority, San Diego Community Power, San Jacinto Power, San José Clean Energy, Santa Barbara Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power, and Valley Clean Energy. 3 Assigned Commissioner’s Scoping Memo and Ruling, Rulemaking (R.) 25-07-013 (Feb. 3, 2026). 4 Exec. Order No. N-5-24 (Oct. 30, 2024).
2 “11 percent higher than the national average.”5 Energy costs are a significant contributor to this burden. Monthly energy bills in California are 13 percent higher than the national average, and retail electricity prices experienced larger increases than any other state between 2019 and 2024.6 Electricity rates have far outpaced inflation and, outside of the District of Columbia, California is the only state to have seen electricity rates rise faster than national median weekly earnings.7

For many households, particularly low- and moderate-income families, these trends are not abstract statistics. They translate into difficult financial trade-offs and ongoing instability. In this environment, the California Climate Credit is not a silver bullet, but it remains an important tool among the broader set of mechanisms under consideration.

The Scoping Ruling proposes in Phase 1A to pause the 2026 Climate Credit to consider immediate but potentially interim changes pending broader consideration of changes to the timing, eligibility, or administration of the residential gas and electric Climate Credit in Phase 1B.8 These Phase 1A changes, whether on an interim or permanent basis, are being proposed prior to any reevaluation of the Commission’s previously established Climate Credit objectives and priorities. They are also being proposed prior to any record development or analysis as to the impact such changes will have on Californians struggling with the affordability crisis. In fact, altering the timing without understanding high-bill seasonality, arrearages, and customer payment behavior may reduce the practical value of the benefit, create additional cash flow challenges for vulnerable households, and increase customer confusion. Overall, there is simply 5 Hanna Panreck, Newsom confronted on California being the ‘highest cost of living’ state in the US amid affordability crisis, Yahoo News (Feb. 22, 2026). 6 Naveena Sadasivam & Clayton Aldern, What’s Behind Your Eye-Popping Power Bill? We Broke It Down, Region by Region, Grist (Feb. 18, 2026).
7 Severin Borenstein, Locating the U.S. Electricity Affordability Crisis, Energy Institute Blog, (Jan. 26, 2026,
8 Scoping Ruling at 7.
3 no evidence in this proceeding which demonstrates that moving the Climate Credit from its established April and October distribution will improve affordability outcomes.

If the Commission’s goal is to improve affordability for Californians, the 2026 Climate Credit should proceed as scheduled. At the same time, the Commission and stakeholders can revisit the Commission’s previously established Climate Credit objectives and priorities, and undertake a deliberate, data-driven process to evaluate how best to maximize the Climate Credit’s impact going forward. Evidence-based policymaking, grounded in a clear record and meaningful stakeholder input, must guide any changes to a program that millions of Californians depend upon.

CalCCA provides the following recommendations, as well as answers to the Scoping Ruling’s questions:
• Immediate modifications to the Climate Credit for 2026 and 2027 are premature and should be postponed given risks of increasing administrative costs, reducing net affordability benefits, and potential customer confusion; • The Commission must ensure clear and accurate customer communications regarding any Climate Credit changes, with CCAs meaningfully involved in developing and reviewing messaging to avoid customer confusion and ensure neutrality; and
• Prior to implementing Climate Credit changes, the Commission should reevaluate its Climate Credit objectives and priorities, and only base decisions on an in-depth analysis and a full evidentiary record.

II. SHORT-TERM SPECULATIVE CLIMATE CREDIT CHANGES MAY NOT

IMPROVE AFFORDABILITY AND SHOULD BE POSTPONED PENDING

ADEQUATE ANALYSIS AND RECORD DEVELOPMENT
The short-term, speculative proposed Phase 1A changes to the Climate Credit may not meaningfully improve affordability and will be based on assumption or speculation rather than fact. As explained below, multiple questions require consideration and analysis before Climate Credit changes should be made, including:
4 • Does moving the Climate Credit to summer-peaking months adequately protect customers in winter-peaking areas?
• Do the increased administrative costs and operational inefficiencies associated with moving the Climate Credit provide a net benefit in terms of affordability? • Is pausing the Climate Credit to later in the year instead of any earlier distribution better for customers from a time value of money perspective? • Is changing the Climate Credit already expected in April fair to customers? • How will customer confusion with an interim and then potentially different permanent change to the timing, eligibility, and number of distributions impact customers?
Until each of these questions (and likely other considerations) are adequately analyzed through a fact-based record, the Commission should postpone any changes to the Climate Credit.

A. Changing the Climate Credit Timing Based on Presumptions of “High-Billed Months” Without any Analysis of Impacts Should be Rejected California’s diverse climate zones and varying degrees of customer access to technologies mean there may not be an obvious, one-size-fits-all choice for when the Climate Credit should be dispersed. While moving distributions to summer months may benefit customers in cooling-dominant regions, it does not address winter-peaking areas or Commission designated Areas of Affordability Concern. The Commission is considering pausing the April Climate Credit, but the record does not demonstrate that April is categorically inappropriate as a “high-billed” month. The Scoping Ruling acknowledges this variation by leaving the small and multi-jurisdictional utilities territories unchanged, yet it does not analyze comparable winter-bill dynamics within the larger IOU territories.9 Absent granular analysis, pausing and shifting the Climate Credit cannot be demonstrated to improve affordability for all Californians and may do the opposite.
9 Scoping Ruling at 9.
5 B. Proposed Interim Changes to the Climate Credit Fail to Consider Increased Administrative Costs and Operational Inefficiencies
Operational realities further underscore the impracticality of a near-term pause and shift.

Pacific Gas and Electric Company (PG&E) explained in a recent motion that bill inserts for the April Climate Credit need to be finalized as of March 2, the same day these comments are due.10 Discarding finalized communications, reprinting materials, revising master meter notices, and coordinating revised messaging will result in costs that are either already incurred or imminent and are likely recoverable costs from customers.11 IOUs have previously indicated that shifting a Climate Credit distribution requires at least four months of preparation.12 The costs associated with such changes remain unknown and even if IOUs provide cost estimates in response to Section

4.2 of the Scoping Ruling, CalCCA and other parties would have only five days to evaluate and respond. It also fails to consider anticipated increases in customer inquiries for community choice aggregators (CCA) that will require staff resources and potentially additional costs.

C. The Proposed Timing Changes to Distribution of the Climate Credit Fail to Address the Time Value of Money
If the Commission’s singular objective is to improve affordability, then the timing question warrants closer scrutiny. If earlier distribution maximizes affordability, why is the Climate Credit not being issued in January? Basic principles of the time value of money suggest 10 Motion of Pacific Gas and Electric Company (U 39 E) for Leave to File Comments Concerning Issue 1 of Phase 1A on the Commissioner’s February 3, 2026 Scoping Memo and Ruling (including Attachment A: PG&E’s Proposed Comments on the Commissioner’s Scoping Memorandum and Ruling) (PG&E Motion), R.25-07-013 (Feb. 6, 2026), Attachment A, at 2 (emphasis added). 11 Id. at 3.
12 Post-Prehearing Conference Statement of Southern California Edison Company (U 338-E), R.25- 07-013 (Dec. 8, 2025), at 5 (SCE estimating the process to move the October 2026 credit to September 2026 would require six months); Post-Prehearing Conference Statement of Pacific Gas and Electric Company (U 39 M), R.25-07-013 (Dec. 8, 2025), at 7 (PG&E estimating at least four months to accelerate the October 2026 credit); Post-Prehearing Conference Comments of San Diego Gas & Electric Company (U 902 M) on Order Instituting Rulemaking to Improve the California Climate Credit, R.25-07-013 (Dec. 8, 2025), at 2 (SDG&E estimating 14-16 weeks just to move the October credit.). 6 that customers derive the greatest benefit from receiving funds sooner rather than later, allowing them to retain and deploy their own resources during periods of financial strain. Yet the total annual Climate Credit does not change based on whether it is distributed in one, two, or multiple installments, nor does it change based on the month in which it is issued. What does change is the net value customers ultimately receive if the Commission’s action increases administrative implementation costs. Those costs are particularly consequential in a year when the total Credit amount is already $40 to $63.28 lower than 2025,13 and increased costs would likely erode the remaining financial and affordability benefits to customers.

D. The Proposed Changes Fail to Consider Customer Expectations of the Climate Credit’s Distribution
Customers have come to anticipate and budget around the established April distribution.

Altering that timing imposes real costs in the form of disrupted household planning and reduced predictability. If greater affordability is truly the guiding principle, then immediate changes that introduce new costs, diminish net benefits, and disrupt customer expectations are not supported by either economic logic or the current record.

E. Customer Confusion and Inaccurate Messaging Outweigh Any Perceived Benefits of Interim Changes to the Climate Credit and Necessitate Future CCA Involvement
The timing of the proposed pause and shift in eventual distribution of the Climate Credit also presents acute customer communication risks. The Pause PD may be approved only weeks before the April Climate Credit would otherwise be distributed and the results of this phase remain unknown.14 That compressed timeline leaves insufficient opportunity for utilities, CCAs, 13 See R.25-07-013, Proposed Decision Pausing the Distribution of the Large Electric Utilities’ 2026 Residential Climate Credit (Feb. 9, 2026) (Pause PD), at 6. 14 Pause PD.
7 and the Commission to develop and implement clear, coordinated messaging about the potential pause and future distributions.

1. Risks of Customer Confusion Must be Mitigated in any Change to the Climate Credit
First, it is not sufficient to inform customers that the credit will be received “later.” Provided the broad call for “immediate” changes in Questions 1 and 5, there is the potential for uncertainty regarding eligibility in future distributions. For example, customers expecting the credit in April, who may have made financial decisions based on the expected credit, would not be able to make further financial adjustments without knowing when they would receive the delayed credit. Or what about a customer who moves out of California in June? Normally they would have received the April credit, but now they would receive nothing. In addition, if the Commission ultimately determines that a certain customer class or customers exceeding a certain income threshold would no longer receive the Climate Credit, then customers falling into the new ineligible categories will not be credited for the Climate Credit that had been delayed in April.

Second, the language surrounding both the proposed pause and any future distribution requires careful attention and sufficient time to incorporate meaningful input from all impacted parties. Customer communication must be precise, accurate, and conspicuous. While the phrase “top of customer bills” may invite different interpretations, the intent is to ensure that Climate Credit information is prominent.15 Whether through contrasting colors or clear placement within the bill, the message must clearly state that the credit is part of the Cap-and-Invest program and that changes are a result of the Commission’s interpretation of Assembly Bill (AB) 1207.16 For electronic bills, pop up notices on websites and upon login for payment, with required click 15 Pub. Util. Code § 748.5 (b)(2).
16 Assembly Bill No. 1207 (AB 1207), Ch. 117, Stats. 2025 (Sept. 19, 2025). 8 through acknowledgment, could provide conspicuous notice. Again, the cost and implementation timeline for such modifications are unknown. IOUs have indicated that four months are needed simply to move the October Climate Credit. That estimate does not account for new formatting requirements such as prominent placement on the website and bills.

2. Climate Credit Communications Must be Neutral to Prevent CCA Customer Confusion
Climate Credit communications must also be clear and neutral to prevent CCA customer confusion. In fact, CCAs should be involved in reviewing and shaping these communications.

Although CalCCA believes short-term changes are misaligned with affordability goals, if the Commission proceeds with immediate modifications, adequate time must be provided for CCA participation in the many communications to customers.

Issues relating to the communication of Climate Credit changes raise larger issues that CalCCA seeks to address in this proceeding regarding neutrality in Climate Credit communications. Maintaining competitive neutrality across load serving entities was reaffirmed as a high priority policy objective in the previous Climate Credit decision.17 For example, the Pause PD includes language that illustrates a common issue and concern when communicating the Climate Credit. Table 1 of the Pause PD refers to “Investor-owned Electric Utilities Residential Climate Credit Amounts for 2025 and 2026.”18 While IOUs administer the credit, it is not an IOU benefit—it is a state-mandated Climate Credit. This language is repeated in the title of the Pause PD as well as in other portions of the body. That misperception is problematic.

With a potential pause and redistribution, the importance of accurate and neutral communication 17 D.12-12-036, at 69-70; D.21-08-026, at 12-13.
18 Pause PD at 6.
9 becomes even greater. CCAs must have the opportunity to participate in crafting all communications surrounding the Climate Credit that will reach their customers.

Communications must clearly explain the source of the Climate Credit, the reason for any pause, and the timing of future distributions. Follow up communications will also be required when the Climate Credit is ultimately issued. These challenges cannot be fully addressed within the compressed timeframe currently contemplated and without CCA involvement. Because the “top of customer bills” requirement and outreach plan updates must be completed by January 1, 2027, limiting additional changes will make meeting that deadline more feasible.

III. INSTEAD OF RUSHING TO CHANGE THE CLIMATE CREDIT ON AN

INTERIM BASIS, THE COMMISSION SHOULD REVISIT THE CLIMATE

CREDIT POLICY OBJECTIVES AND PRIORITIES AND MAKE DECISIONS

BASED ON IN-DEPTH ANALYSIS AND A COMPLETE RECORD
Given these and other likely considerations that must be analyzed prior to any change to the Climate Credit, CalCCA recommends that the Commission: (1) reconsider and update the policy objectives and priorities originally adopted with substantial stakeholder input in the prior Climate Credit proceedings in Decisions (D.) 12-12-033 and D.21-08-026; and (2) develop and make any decisions on Climate Credit changes only based on an evidence-based record.

A. The Commission Should Revisit the Climate Credit Objectives and Priorities Prior to Any Changes to the Climate Credit
CalCCA stated in its Opening Comments on the Order Instituting Rulemaking to Improve the California Climate Credit (OIR) that the Commission should first revisit the Climate Credit policy objectives and priorities originally adopted with substantial stakeholder input in D.12-12-03319 and affirmed in D.21-08-026.20 Among other objectives, the Commission 19 D.12-12-033, Decision Adopting Cap-and-Trade Greenhouse Gas Allowance Revenue Allocation Methodology for the Investor-Owned Electric Utilities, R.11-03-012 (Dec. 20, 2012). 20 D.21-08-026, Decision Adopting Customer Climate Credit Updates, R.20-05-002 (Aug. 19, 2021).
10 prioritized reducing adverse impacts on low-income households, maintaining competitive neutrality across load serving entities, preserving the carbon price signal, and preventing economic leakage. Revisiting the objectives and determining current priorities will assist in framing stakeholder positions on potential Climate Credit modifications. However, the Commission appears to have abandoned these considerations for the stated rationale of needing to “improve the affordability benefit” and the requirement in Public Utilities Code section 748.5(a)(3)21 to distribute credits in “high-billed” months.22 B. A Data-Driven Process and Full Evidentiary Record Should be Developed Prior to Any Changes to the Climate Credit
Public Utilities Code section 748.5(a)(3) also does not require the Commission to take immediate action. In fact, to properly carry out the Legislature’s goal of maximizing customer electric bill affordability, the Commission should be engaging stakeholders to develop a robust record that supports potential movement of the credit. Instead, in a rush to move credits to the perceived “high-bill” months of the summer, analysis and consideration of all customers have been eschewed. Section 748.5(a)(3) does instruct that the credit be provided in no more than four “high-billed months” to maximize bill affordability, but it also allows the Commission discretion “to address extreme, unforeseen, and temporary circumstances.” Moving the credit on an interim basis based on responses to the questions in Section 4.2 of the Scoping Ruling cannot be proven to maximize bill affordability.

CalCCA supports aligning the Climate Credit with periods of greatest affordability impact. But that determination must be supported by evidence, not assumption. The responses by parties to questions in Section 4.2 of the Scoping Ruling will not provide the opportunity for 21 All subsequent code sections cited herein are references to the California Public Utilities Code unless otherwise specified.
22 Scoping Ruling at 8-9.
11 parties to engage and test those assumptions. To accurately implement section 748.5 as intended by the Legislature, the Commission should refrain from immediate action and instead proceed through a structured, data driven process that allows for the evaluation of eligibility, timing, frequency, customer communications, and bill impacts under a set of guiding principles.

Otherwise, the notion that the Climate Credit will be used to address “high billed” months will likely only be true for a select portion of customers.

IV. CALCCA’S RESPONSES TO SECTION 4.2 OF THE SCOPING RULING

4. Would it benefit customer affordability for the Commission to order the spring 2027 gas Climate Credit to instead be delivered as a winter credit in February 2027?
Maybe, but it should be supported by data and analysis. 12 5. Should the Commission order any other changes to the residential Climate Credit to maximize affordability that can take effect in 2026? No. See Sections II and III, herein.

6. Due to timelines driven by ERRA proceedings, should changes to the residential electric Climate Credit made in Phase 1A also apply for 2027, such that these interim benefits may be experienced in that year as well? The question assumes “benefits” will be achieved by moving the Climate Credit without further defining those benefits or providing analysis. See Sections II and III, herein.

8. What specific direction and authority do the utilities need to implement the immediate affordability actions approved in Phase 1A?
CalCCA will reserve its response to this question, if any, to potential reply comments.

10. What direction must the Commission give to ensure compliance with Pub.

Util. Code Section 748.5 (b)(2), regarding updates to the customer outreach plan?
a. How should “the top of customer bills” be defined and implemented, in line with this code section? What billing limitations exist? b. For customers who receive paper bills, do bill inserts placed on top of paper bills qualify? What placement complies for e-billed customers? c. How can other outreach be aligned with these messages in line with the spirit of this code section?
d. What approval process should apply to these updates to outreach? What new authority, if any, should be delegated to Commission staff? See Sections II D. and E, herein.
13 11. What direction do the utilities need to effectuate the transfer of 5% of revenues to the State Treasury for deposit in the California Transmission Accelerator Revolving Fund pursuant to Pub. Util. Code Section 748.5(d)? What documentation should the Utilities provide to the Commission demonstrating their transmittal of the funds annually? Overall, what action must the Commission take to ensure compliance with this code section? CalCCA reserves its response to this question, if any, to reply comments.

V. CONCLUSION
CalCCA supports thoughtful reform of the Climate Credit to maximize affordability benefits. However, short-term changes both in 2026 and 2027—without a developed evidentiary record, without meaningful opportunity for party input, and without analysis of operational and customer impacts—does not advance that objective. A deliberate and evidence-based approach will ensure that any modifications to the Climate Credit will enhance affordability, maintain transparency, and avoid unnecessary customer confusion and cost.

Respectfully submitted,
Leanne Bober,
Director of Regulatory Affairs and Deputy
General Counsel

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
March 2, 2026

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Improve the
California Climate Credit.

R.25-07-013
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S OPENING COMMENTS ON

THE PROPOSED DECISION PAUSING THE DISTRIBUTION OF THE LARGE ELECTRIC UTILITIES’ 2026 RESIDENTIAL CLIMATE CREDIT
Leanne Bober,
Director of Regulatory Affairs and Deputy
General Counsel
Kevin Johnston,
Regulatory Counsel

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
1121 L Street, Suite 400
Sacramento, CA 95814
(510) 980-9459
E-mail: [email protected]
March 2, 2026
i

TABLE OF CONTENTS
I. INTRODUCTION ...............................................................................................................1 II. THE PROPOSED DECISION SHOULD BE REJECTED BECAUSE OF

PROCEDURAL DEFICIENCIES AND LACK OF NOTICE OF AN APRIL
CLIMATE CREDIT PAUSE ...............................................................................................2 III. THE PROPOSED DECISION’S AFFORDABILITY RATIONALE IS UNSUPPORTED AND SHOULD BE REJECTED ...........................................................4 A. The Proposed Decision’s Unsupported Affordability Justification Ignores the Increased Costs Caused by an Unanticipated Pause .............................5 B. An Affordability Justification Based on Moving the Climate Credit to High Billed Months Fails to Recognize that April is a High-Billed Month for Some Customers .....................................................................................6 IV. POTENTIAL CUSTOMER CONFUSION AND MESSAGING RISKS

OUTWEIGH ANY PERCEIVED BENEFITS OF A CLIMATE CREDIT
PAUSE .................................................................................................................................6 V. CONCLUSION ....................................................................................................................8

APPENDIX
ii

TABLE OF AUTHORITIES
Statutes
Pub. Util. Code § 748.5(a)(3).......................................................................................................... 4 Public Utilities Code Section 748.5(a)(3) ....................................................................................... 4 section 748.5 ............................................................................................................................... 5, 6 section 748.5(a)(3) .......................................................................................................................... 5 Other Authorities
Assembly Bill 1207......................................................................................................................... 4 Assembly Bill No.1207 (AB 1207), Ch. 117, Stats. 2025 (Sept. 19, 2025) ................................... 4 California Public Utilities Commission Proceedings
R.25-07-013 ........................................................................................................................ 1, 2, 3, 5 California Public Utilities Commission Rulings
Assigned Commissioner’s Scoping Memo and Ruling.................................................................... 2 Scoping Ruling........................................................................................................................ 2, 4, 6 iii
SUMMARY OF RECOMMENDATIONS1
CalCCA recommends the Commission withdraw the Proposed Decision pausing the Climate Credit, because:
• The Proposed Decision was issued without any notice or opportunity for parties to weigh in on the reasonableness of the pause;
• Rather than increasing affordability for all customers, the Proposed Decision will likely increase costs of issuing the Climate Credit and harm customers who experience high-billed months in April; and
• Pausing the Climate Credit in April, without sufficient education and outreach, will cause customer confusion and detract from customer affordability. 1 Acronyms used herein are defined in the body of this document.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Improve the
California Climate Credit.

R.25-07-013
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S OPENING COMMENTS ON

THE PROPOSED DECISION PAUSING THE DISTRIBUTION OF THE LARGE ELECTRIC UTILITIES’ 2026 RESIDENTIAL CLIMATE CREDIT
The California Community Choice Association2
(CalCCA) submits these comments
pursuant to Rule 14.3 of the California Public Utilities Commission (Commission) Rules of Practice and Procedure3 on the proposed Decision Pausing the Distribution of the Large Electric Utilities’ 2026 Residential Climate Credit4(Proposed Decision), dated February 9, 2026.

CalCCA respectfully requests the Proposed Decision be withdrawn to remove consideration of pausing the April Climate Credit.

I. INTRODUCTION
CalCCA is committed to improving customer affordability and the Climate Credit remains an important tool in achieving that goal. Therefore, the Proposed Decision pausing the April 2026 Climate Credit distribution should be withdrawn as it: (1) is procedurally deficient; (2) will not advance affordability as it will likely increase costs and cause operational disruption; and (3) risks significant customer confusion.
2 California Community Choice Association represents the interests of 24 community choice electricity providers in California: Apple Valley Choice Energy, Ava Community Energy, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance of Southern California, CleanPowerSF, Desert Community Energy, Energy For Palmdale’s Independent Choice, Lancaster Energy, Marin Clean Energy, Orange County Power Authority, Peninsula Clean Energy, Pico Rivera Innovative Municipal Energy, Pioneer Community Energy, Pomona Choice Energy, Rancho Mirage Energy Authority, Redwood Coast Energy Authority, San Diego Community Power, San Jacinto Power, San José Clean Energy, Santa Barbara Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power, and Valley Clean Energy. 3 State of California Public Utilities Commission, Rules of Practice and Procedure, California Code of Regulations Title 20, Division 1, Chapter 1 (May 2021), https://webproda.cpuc.ca.gov/- /media/cpuc-website/divisions/administrative-law-judge-division/documents/rules-of-practice-and-procedure-may-2021.pdf. 4 Proposed Decision Pausing the Distribution of the Large Electric Utilities’ 2026 Residential Climate Credit, Rulemaking (R.) 25-07-013 (Feb. 9, 2026), https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101732.PDF. 2 Any modification to the timing, eligibility, or administration of the Climate Credit must be supported by a clear record and careful analysis of customer impacts. The Proposed Decision lacks the evidentiary foundation necessary to demonstrate that pausing the April Climate Credit will improve affordability, particularly in light of the near-term costs and confusion the pause would create. Absent such support, the Commission should refrain from making immediate changes and instead proceed through a structured, data-driven Phase 1 process.

As set forth below, CalCCA recommends withdrawal of the Proposed Decision for the following reasons:
• The Proposed Decision was issued without any notice or opportunity for parties to weigh in on the reasonableness of the pause;
• Rather than increasing affordability for all customers, the Proposed Decision will likely increase costs of issuing the Climate Credit and harm customers who experience high-billed months in April; and
• Pausing the Climate Credit in April, without sufficient education and outreach, will cause customer confusion and detract from customer affordability.

II. THE PROPOSED DECISION SHOULD BE REJECTED BECAUSE OF

PROCEDURAL DEFICIENCIES AND LACK OF NOTICE OF AN APRIL

CLIMATE CREDIT PAUSE
The Proposed Decision should be rejected based on procedural deficiencies and the lack of any record regarding the reasonableness of such a pause. Parties were never afforded a meaningful opportunity to comment, analyze, or develop a record regarding the operational, legal, and customer impacts of such a pause. The first time the potential for an April Climate Credit pause was raised was in the Scoping Ruling issued February 3, 2026.5 Pacific Gas and Electric Company (PG&E) voiced shared concerns regarding such a pause in a Motion filed three days later on February 6, 2026, when it stated that:
5 See Assigned Commissioner’s Scoping Memo and Ruling (Scoping Ruling), R.25-07-013 (Feb. 3, 2026), at 7 (Phase 1A, Issue 1 asks “[w]hether the Commission should order the large electric utilities to pause the distribution of the 2026 residential [CC] while considering other issues in this phase”), https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K166/597166396.PDF. 3 At no point in the Order Instituting Rulemaking, the prehearing conference notice and draft agenda, the prehearing conference itself, or at any other time, did the Commission raise the possibility that it might order investor-owned utilities to pause the April 2026 Climate Credit distribution.6
PG&E expressed legal concerns regarding the procedural deficiencies of pausing the April 2026 Climate Credit distribution given that no notice or opportunity to be heard on the matter was afforded to parties. In addition, PG&E raised concerns about operational issues, affordability, and customer confusion. CalCCA agrees with the concerns cited by PG&E, which should have been addressed prior to this Proposed Decision being issued on February 9, 2026.

The Proposed Decision’s attempts to explain away the procedural deficiencies fall short for many reasons. As noted in the Proposed Decision, one justification for this rapid and unanticipated “pause” was that “[n]o party specifically contemplated pausing the spring 2026 distribution to allow it to be distributed later this year, but neither did any party identify any reason why the utilities could not do so.”7 Parties cannot be expected to preemptively address every hypothetical modification that the Commission might consider, particularly when such modifications were never identified as issues in the proceeding. The absence of opposition to an unraised proposal does not constitute support, nor does it substitute for a developed record.

In addition, the Proposed Decision cites a past change to the timing of the upcoming Climate Credit when, in February 2023, the Climate Credit was accelerated in response to natural gas price spikes in winter 2023.8 However, an acceleration of the distribution of the Climate Credit (i.e., that the Climate Credit would be provided one or two months earlier) does not necessarily justify a “pause” (i.e., withholding) the Climate Credit. Accelerating the distribution of the Climate Credit resulted in protecting customers from bill increases, whereas pausing the distribution of the Climate Credit would likely result in customer confusion, and harm customers who have been expecting the Climate Credit to help reduce their bills in April. 6 See Motion of Pacific Gas and Electric Company (U 39 E) for Leave to File Comments Concerning Issue 1 of Phase 1A on the Commissioner’s February 3, 2026 Scoping Memo and Ruling (including Attachment A: PG&E’s Proposed Comments on the Commissioner’s Scoping Memorandum and Ruling) (PG&E Motion), R.25-07-013 (Feb. 6, 2026), at 2 (emphasis added), https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K100/598100966.PDF. 7 Proposed Decision at 8 (emphasis added).
8 Ibid.
4 Finally, the Proposed Decision notes the “advance notice” of the “possibility” of a pause in the Scoping Ruling issued six days earlier.9 Six days essentially equates to no notice, especially without the ability of parties to comment on the idea of a potential pause prior to the issuance of a Proposed Decision.

Had pausing the April Climate Credit been noticed as a potential outcome, CalCCA would have fully engaged on this issue and provided evidence or raised concerns regarding operational impacts, customer communications, and affordability consequences, which are discussed in detail below. In addition, if the Commission believed immediate action was statutorily required following enactment of Assembly Bill 1207,10 it is unclear why such action was not initiated earlier considering the bill was signed September 19, 2025, and the Order Instituting Rulemaking has been open since July 24, 2025.11 Moreover, Public Utilities Code section 748.5(a)(3) provides the Commission discretion to distribute the credit “to address extreme, unforeseen, and temporary circumstances.”12 Withdrawing the Proposed Decision to avoid customer confusion, stranded communication costs, and administrative inefficiencies caused by a last-minute pause squarely fits within that discretion.

CalCCA agrees with PG&E that the Commission’s departure from standard Commission practice raises concerns regarding the lack of notice and opportunity to be heard. In addition, as discussed below, serious affordability and customer communication issues arise in the context of the pause. For these reasons, the Proposed Decision should be withdrawn and further consideration of the reasonableness of this pause should be undertaken.

III. THE PROPOSED DECISION’S AFFORDABILITY RATIONALE IS

UNSUPPORTED AND SHOULD BE REJECTED
Aside from the procedural infirmities, the Proposed Decision should be rejected as its explanation for pausing the April Climate Credit based on the possibility of “greater affordability impacts” is unsubstantiated.13 First, the record contains no data, modeling, or analysis demonstrating that delaying the April distribution will actually increase affordability across the 9 Ibid.
10 Assembly Bill No.1207 (AB 1207), Ch. 117, Stats. 2025 (Sept. 19, 2025), https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill_id=202520260AB1207. 11 Proposed Decision at 2.
12 Pub. Util. Code § 748.5(a)(3). All section references herein are to the California Public Utilities Code, unless otherwise noted.
13 Proposed Decision at 2.
5 board. To the contrary, if pausing the credit generates additional administrative and communication costs that are ultimately recovered from ratepayers, the net Climate Credit benefit will be reduced. In addition, while the Proposed Decision states that it is increasing affordability in accordance with section 748.5(a)(3) by ensuring that the credits be distributed in “high-billed” months, this rationale fails to recognize that some customers actually experience “high-billed” months in April (i.e., winter peaking customers) and therefore moving the Climate Credit will decrease affordability for those customers.

A. The Proposed Decision’s Unsupported Affordability Justification Ignores the Increased Costs Caused by an Unanticipated Pause
The Proposed Decision does not evaluate the incremental administrative and communication costs associated with a late stage pause. PG&E explained in its Motion that bill inserts need to be finalized as of March 2, the day these comments are due.14 Not to mention, the investor-owned utilities (IOU) have previously indicated that shifting a Climate Credit distribution requires a minimum of four months of preparation.15 Discarding finalized communications, reprinting materials, revising master meter notices, and coordinating revised messaging will generate real and likely recoverable costs from customers.16 In addition, community choice aggregators (CCA) anticipate increased customer inquiries that will require staff resources and therefore costs. These costs diminish the net affordability benefit of the Climate Credit. The record of this proceeding does not address these impacts in any meaningful way.

Those costs, already incurred and forthcoming, are expected to be recovered from ratepayers, thereby eroding the intended affordability gains. When combined with unrecoverable CCA administrative burdens, the overall effect of the Climate Credit will be diminished for customers.

CalCCA supports aligning the Climate Credit with periods of greatest affordability impact. However, that determination must be supported by evidence, not assumption. To 14 PG&E Motion, Attachment A, at 2.
15 Post-Prehearing Conference Statement of Southern California Edison Company (U 338-E), R.25- 07-013 (Dec. 8, 2025), at 5 (SCE estimating the process to move the October 2026 credit to September 2026 would require six months); Post-Prehearing Conference Statement of Pacific Gas and Electric Company (U 39 M), R.25-07-013 (Dec. 8, 2025), at 7 (PG&E estimating at least four months to accelerate the October 2026 credit); Post-Prehearing Conference Comments of San Diego Gas & Electric Company (U 902 M) on Order Instituting Rulemaking to Improve the California Climate Credit, R.25-07-013 (Dec. 8, 2025), at 2 (SDG&E estimating 14-16 weeks just to move the October credit.). 16 PG&E Motion, Attachment A at 3.
6 accurately implement section 748.5, the Commission should refrain from immediate action and instead proceed through a structured Phase 1 process that establishes guiding principles for Climate Credit policy and simultaneously evaluates eligibility, timing, frequency, customer communications, and bill impacts in a standardized manner. Only through a comprehensive and integrated analysis can the Commission ensure that any modifications maximize transparency and affordability benefits.

B. An Affordability Justification Based on Moving the Climate Credit to High Billed Months Fails to Recognize that April is a High-Billed Month for Some Customers
Any affordability justification based on moving the Climate Credit to “high billed months” fails to recognize that April is a high-billed month for some customers. The Proposed Decision does acknowledge that peak billing periods vary by service territory.17 For example, customers in certain regions experience high winter bills, while others peak in summer. The record does not demonstrate that April is categorically inappropriate as a “high-billed” month, nor does it analyze regional or climate-zone variability across the large IOU territories. While moving distributions to summer months may benefit customers in cooling-dominant regions, it does not address winter-peaking areas, some of which are Commission-designated Areas of Affordability Concern.
18 The Proposed Decision acknowledges variation by leaving the small and multi-jurisdictional utilities territories unchanged, yet it does not analyze comparable winter-bill dynamics within the larger IOU territories. Absent granular analysis, pausing the April Climate Credit risks could create outsized affordability impacts in regions where April distributions meaningfully offset seasonal bills.

IV. POTENTIAL CUSTOMER CONFUSION AND MESSAGING RISKS

OUTWEIGH ANY PERCEIVED BENEFITS OF A CLIMATE CREDIT PAUSE The timing of the proposed pause also presents acute customer communication risks. The Proposed Decision may be approved only weeks before the April Climate Credit would otherwise be distributed. Additionally, the multiple and complex public policy discussions and 17 Proposed Decision at 5 (citing the Scoping Ruling at 9). 18 See California Public Utilities Commission, 2021 and 2022 Annual Affordability Report (2023), https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/affordability-proceeding/2021-2022/2021-and-2022-annual-affordability-report.pdf. 7 rulemakings involving the Climate Credit occurring in the Legislature,19 California Air Resources Board,
20 and the Commission require thoughtful messaging to ensure sufficient customer awareness prior to implementing a change that directly impacts bills. That compressed timeline leaves insufficient opportunity for the large electric utilities, CCAs, and the Commission to develop and implement clear, coordinated messaging to customers.

Moreover, it is not sufficient to inform customers that the credit will be received “later.” Phase 1A Part Two may make other “immediate” changes that create uncertainty regarding future distributions. For example, customers expecting the credit in April may have made financial decisions based on the expected credit and would now not be able to make further financial adjustments without knowing when they would receive the delayed credit.

The Proposed Decision’s language itself illustrates the communication challenge. For example, Table 1 refers to “Investor-owned Electric Utilities Residential Climate Credit Amounts for 2025 and 2026.”21 While IOUs administer the credit, it is not an IOU benefit—it is a state-mandated Climate Credit. This language is repeated in the title of the Proposed Decision as well as in other portions of the body. Framing the credit as belonging to IOUs risks reinforcing the mistaken perception that it is an IOU-driven benefit or goodwill gesture. This could be further exacerbated if a customer departs IOU service for a CCA and may believe they are losing the April Climate Credit because of this change.

The language surrounding both the proposed pause and any future distribution of the credit will require significant attention to detail and sufficient time to ensure meaningful input from all impacted parties. CalCCA believes the nature of the pause and the appropriate language surrounding the credit both used in the Proposed Decision and contemplated in Phase 1A Part Two, requires CCA participation and feedback. Language must be precise, accurate, and delivered in a manner that does not confuse the average customer. Achieving this clarity for 19 See Air Resources Board, Cap-and-Invest Program Amendments: CANDI Updates — Joint Legislative Committee on Climate Change Policies Presentation (Feb. 23, 2026), https://climatechangepolicies.legislature.ca.gov/system/files/2026-02/carb_202602_candi-updates-jlcccp-presentation.pdf. 20 See California Air Resources Board, Regulation for the California Cap on Greenhouse Gas Emissions and Market-Based Compliance Mechanisms: 2024 Amendments — Standardized Regulatory Impact Assessment (Apr. 9, 2024), https://ww2.arb.ca.gov/sites/default/files/2024-04/nc-Cap-and-Trade_SRIA2024.pdf. 21 Proposed Decision at 6.
8 customers is impossible in the two weeks between potential approval of this Proposed Decision and the April Climate Credit distribution date.

V. CONCLUSION
CalCCA recognizes the value of optimizing the affordability benefits of the Climate Credit and supports thoughtful reform. However, pausing the April 2026 distribution on such short notice—without a developed evidentiary record, without meaningful opportunity for party input, and without analysis of operational and customer impacts—does not advance that objective.

The Commission should decline to pause the April 2026 Climate Credit and withdraw the Proposed Decision.

Respectfully submitted,
Leanne Bober,
Director of Regulatory Affairs and Deputy
General Counsel

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
March 2, 2026
A-1

APPENDIX A
TO
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S OPENING COMMENTS ON

THE PROPOSED DECISION PAUSING THE DISTRIBUTION OF THE LARGE ELECTRIC UTILITIES’ 2026 RESIDENTIAL CLIMATE CREDIT

PROPOSED CHANGES TO FINDINGS OF FACT, CONCLUSIONS OF LAW

AND ORDERING PARAGRAPHS
Proposed text deletions show as bold and strikethrough
Proposed text additions show as bold and underlined

FINDINGS OF FACT

CONCLUSIONS OF LAW

ORDERING PARAGRAPHS
New Order:

The Proposed Decision is withdrawn.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Oversee the
Resource Adequacy Program, Consider
Program Reforms and Refinements, and
Establish Forward Resource Adequacy
Procurement Obligations.

R.25-10-003
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S
TRACK 1 PROPOSALS ON TRANSACTABILITY ISSUES
Leanne Bober,
Director of Regulatory Affairs and
Deputy General Counsel
Lauren Carr,
Senior Manager, Regulatory Affairs and
Market Policy
Eric Little,
Director of Market Design
Andrew D. Mills,
Director of Data Analytics

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
1121 L Street, Suite 400
Sacramento, CA 95814
Telephone: (510) 980-9459
E-mail: [email protected]
March 3, 2026
i

TABLE OF CONTENTS
I. INTRODUCTION ...............................................................................................................1 II. THE REPORT DIMINISHES THE PROBLEMS WITH SOD AND DOES

NOT ADDRESS THE CORE AFFORDABILITY ISSUE HOURLY LOAD
OBLIGATION TRADING IS INTENDED TO ADDRESS ...............................................4 III. HOURLY LOAD OBLIGATION TRADING SHOULD BE ADOPTED TO

ALLOW LSES TO TRANSACT AT THE SAME GRANULARITY AS THE
SOD REQUIREMENTS ......................................................................................................8 IV. THE COMMISSION SHOULD INVEST IN SOFTWARE AND SYSTEMS TO AUTOMATE THE RA VALIDATION PROCESS ...................................................11 V. IF THE COMMISSION DECLINES TO INVEST IN SYSTEMS TO

AUTOMATE THE RA VALIDATION PROCESS, IT SHOULD ADOPT
TEMPORARY GUARDRAILS TO AID IN ASSESSING COMPLIANCE ...................12 VI. CONCLUSION ..................................................................................................................13

APPENDIX A
ii
SUMMARY OF RECOMMENDATIONS1
CalCCA proposes the Commission:
• Adopt hourly load obligation trading to allow LSEs to transact at the same granularity as the SOD requirements to promote affordability while maintaining reliability requirements;
• Invest in the software and systems to automate the RA validation process, given it appears the existing manual process is interfering with the adoption of fully vetted and well-supported policy proposals; and
• If the Commission declines to invest in automation of the RA validation process, adopt temporary guardrails to aid in assessing compliance.

1 Acronyms used herein are defined in the body of this document.

BEFORE THE PUBLIC UTILITIES COMMISSION

R.25-10-003
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S
TRACK 1 PROPOSALS ON TRANSACTABILITY ISSUES
California Community Choice Association2
(CalCCA) submits these proposals pursuant
to the Assigned Commissioner’s Scoping Memo and Ruling3(Scoping Ruling), dated December 12, 2025, and Administrative Law Judge’s Ruling on Energy Division’s Transactability Report and Modifying Track 1 Schedule,
4 dated February 24, 2026.

I. INTRODUCTION
Energy Division’s Report on Transactability within the Slice of Day Resource Adequacy Framework,
5 authorized in Decision (D.) 25-06-048,6severely misses the mark in finding that, 2 California Community Choice Association represents the interests of 24 community choice electricity providers in California: Apple Valley Choice Energy, Ava Community Energy, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance of Southern California, CleanPowerSF, Desert Community Energy, Energy For Palmdale’s Independent Choice, Lancaster Energy, Marin Clean Energy, Orange County Power Authority, Peninsula Clean Energy, Pico Rivera Innovative Municipal Energy, Pioneer Community Energy, Pomona Choice Energy, Rancho Mirage Energy Authority, Redwood Coast Energy Authority, San Diego Community Power, San Jacinto Power, San José Clean Energy, Santa Barbara Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power, and Valley Clean Energy. 3 Assigned Commissioner’s Scoping Memo and Ruling, Rulemaking (R.) 25-10-003 (Dec. 12, 2025).
4 Administrative Law Judge’s Ruling on Energy Division’s Transactability Report and Modifying Track 1 Schedule, R.25-10-003 (Feb. 24, 2026).
5 Report on Transactability within the Slice of Day Resource Adequacy Framework, R.25-10-003 (Feb. 2026) (Report).
6 D.25-06-048 authorizes Energy Division to, “conduct an evaluation after a full year of [SOD] implementation to assess the need, benefits, and feasibility of an hourly load obligation trading 2 “[g]iven the limited evidence of need, uncertain magnitude of benefits, and heightened implementation risks, … the potential gains do not outweigh the added complexity and risk of unintended consequences,” of hourly load obligation trading.7 The Report:
• Applies the wrong standard in its assessment, focusing on whether the measure is “necessary” rather than seizing the opportunity to adopt a tool that will bring greater efficiency and affordability to resource adequacy (RA) procurement as market conditions change;
• Materially understates the potential affordability benefits this optimization tool could deliver for ratepayers by ignoring the increased cost resulting from slice-of-day (SOD) implementation; • Presents a “penny wise, pound foolish” approach to RA regulation, failing to acknowledge the criticality of automating RA compliance; and • Continues to seek cover behind potential “unintended consequences”.

Energy Division’s recommendation to continue monitoring market performance leaves CalCCA’s fully vetted and well-supported proposal with the potential to offer significant cost savings hanging in the balance at ratepayers’ expense.

As discussed below, the Energy Division assertions are not well supported and do not address the core issue hourly load obligation trading is intended to address: the exorbitant costs caused by making the Commission’s RA program exceedingly difficult to comply with, while at the same time assessing severe penalties on those who cannot comply. 8 CalCCA addresses
several shortcomings of the Report below and will provide a more detailed response in its opening comments due on March 16, 2026.
mechanism. D.25-06-048, Decision Adopting Local Capacity Obligations for 2026-2028, Flexible Capacity Obligations for 2026, and Program Refinements, R.23-10-011 (June 26, 2025), Ordering Paragraph 11, at 125.
7 Report at 7.
8 These penalties include a financial consequence with a multiplier effect for multiple infractions and, for ESPs and CCAs, a restriction on expansion plans. The severity of these penalties has been readily noticed by LSEs, who will likely procure expensive RA even if it is not necessary to meet their reliability requirements.
3 Hourly load obligation trading offers an opportunity to chip away at the affordability crisis at a time when the Commission should be seizing every opportunity to reduce procurement costs. The inability for load-serving entities (LSE) to transact at the same granularity as the compliance requirement forces LSEs to procure more RA than needed to meet pre-determined reliability targets, unnecessarily driving up RA procurement costs that fall directly on ratepayers.

CalCCA’s analysis, attached to this proposal as Appendix A, suggests hourly obligation trading could save all LSEs $144-$179 million each year. At a time when Californians are struggling to manage rapidly increasing electric bills, dismissing a proposal with such significant potential for cost savings is misguided.

The proposal also recommends guardrails for the initial year of implementation to help manage new administrative tasks that may be necessary to validate showings with load obligation trades. CalCCA is concerned that Energy Division’s continued rejection of hourly load obligation trading is driven largely by the fact that the existing RA compliance mechanisms are no longer sufficient to operate the SOD program. The RA program has become increasingly complex in its over 20-year history, and continued reliance on spreadsheets for validation should not be a barrier to the adoption of sound policy proposals. Given the significant potential benefits of hourly load obligation trading, the Commission should invest in the necessary tools to make the validation process more automated and manageable for Energy Division staff. Still, if the Commission is concerned with the amount of administrative effort this proposal would create, guardrails could help keep those efforts manageable.

In summary, CalCCA recommends that the Commission:
• Adopt hourly load obligation trading to allow LSEs to transact at the same granularity as the SOD requirements to promote affordability while maintaining reliability requirements;
4 • Invest in the software and systems to automate the RA validation process, given it appears the existing manual process is interfering with the adoption of fully vetted and well-supported policy proposals; and • If the Commission declines to invest in automation of the RA validation process, adopt temporary guardrails to aid in assessing compliance.

II. THE REPORT DIMINISHES THE PROBLEMS WITH SOD AND DOES NOT

ADDRESS THE CORE AFFORDABILITY ISSUE HOURLY LOAD

OBLIGATION TRADING IS INTENDED TO ADDRESS
The Report attempts to answer the question of whether transactability issues exist by evaluating whether the measure was necessary to achieve compliance with 2025 RA requirements. The Report finds that “LSEs were able to procure and trade sufficient capacity to meet hourly obligations, with no evidence of unresolved deficiencies or structural market barriers attributable to SOD.”
9 Using this information to imply that there is insufficient justification for hourly load obligation trading ignores the core affordability issue hourly load obligation trading is intended to address. This rationale also ignores the potential for capacity scarcity to return in the future causing an apparent shortfall based on the compliance framework while no actual system reliability gap exists. CalCCA demonstrated this effect with the 2024 test case. While the Report states that over-procurement was “modest” because September 2025 month-ahead showings in the tightest hour showed surplus procurement of 262 megawatts (MW),
10 this does not tell the whole story.

In 2025, LSEs procured significantly more RA capacity than needed to meet their compliance obligations when compared to prior years. This phenomenon can be observed by evaluating aggregated historical RA procurement data from the California Independent System Operator (CAISO), as discussed below. To be clear, CalCCA does not contend that the lack of 9 Report at 6.
10 See Report at 34.
5 transactability has caused all of the incremental procurement observed. Rather, if the new SOD RA mechanism is going to force the procurement of significantly more RA than previously, the system must be made as efficient as possible to avoid unnecessary costs, given the magnitude of the change.

The CAISO annually presents data on the resources shown to meet RA needs.11 The CAISO data includes the years 2019 through 2025. The CAISO data shows a significant increase in the number of RA resources shown starting in 2025, the first year of SOD implementation.

The CAISO uses a single daily value for RA and while SOD uses hourly values, the data is informative in showing the significant increase in the amount of RA shown. This increase comes at a cost. As shown in Figure 1, below, using the 2025 final market price benchmark (MPB) for RA of $11.21/ kilowatt (kW)-month12, the increased cost of SOD is nearly $339 million for the months of May through October.

Figure 1: Average Procurement Relative to RA Target
California’s customers served by LSEs that must comply with the Commission’s SOD regulations should be afforded every opportunity possible to efficiently transact given the significant impact on affordability that the move to SOD has caused.
11 See CAISO Historical Resource Adequacy Showings Aggregate Data. 12 See CPUC MPB Calculations 2025 (Oct. 1, 2025) (2025 MPBs).

May June July August September October
Prior to SOD (% of target shown) 2019 -2024 103% 104% 102% 101% 100% 103% SOD (% of targe shown) 2025 109% 118% 118% 109% 114% 108% Difference 6% 14% 15% 8% 14% 5%
2025 RA Requirement (MW) 38,996 47,496 52,349 50,856 52,091 41,872 2026 RA Market Price Benchmark ($/kW-mo) $ 11.21 $ 11.21 $ 11.21 $ 11.21 $ 11.21 $ 11.21 Total Incremental Cost ($/mo) $ 26,720,203 $ 73,000,172 $ 89,698,883 $ 46,748,335 $ 80,929,640 $ 21,837,678 Total Incremental Cost
$ 338,934,910
Amount of Procurement in 2025 Beyond the
Normal Procurement in 2019-2024 (MW)
Figure 1. Average Procurement to RA Target
2,384 6,512 8,002 4,170 7,219 1,948
6 Data provided in the Report similarly provides evidence of this over-procurement, well beyond the “modest” 262 MW the Report identifies. First, the net qualifying capacity (NQC) of resources under contract in September 2025 “increased by approximately 3,725 MW (8.2 percent)”
13 relative to 2024, while requirements went down by 1,555 MW (3.1 percent),14 a net gain of 5,280 MW of NQC relative to 2024. Second, the achieved reserve margin in September 2025 was far above the required 17 percent. Because reliability is a system attribute, the achieved reserve margin depends on the total contracted resources and the total system requirements. The storage contracted for September 2025 could have contributed to meeting system RA at much greater levels than suggested in the Report. The Report dispatches storage only to meet the requirements and then allocates the 16,269 MW hours of “unused storage” evenly throughout the day.
15 Alternatively the “unused storage” could have been allocated to maximize the avoidable thermal generation. Allocating the “unused storage” in the manner shown in Figure 2, below, achieves a reserve margin of at least 23 percent in all hours of September 2025 or allows 2,175 MW of thermal capacity to be removed while maintaining at least a 17 percent reserve margin in all hours.16 At the current RA MPB, 2,175 MW of capacity beyond that needed to meet RA is valued at $24 million for this single month.
17 If instead we assume that the 2,175 MW of highest
priced RA transactions between the year-ahead and month-ahead deadlines could have been avoided, the savings would be almost $37 million for the single month.18 13 Report at 21.
14 Report at Table 7 (comparing 2024 requirements to 2025 HE18 requirements). 15 Report at 28.
16 CalCCA verified that the charging energy remains sufficient for the storage even after removing 2,175 MW of thermal capacity from the September 2025 portfolio. 17 MPB $11.21/kW-month * 2,175 MW * 1,000 (conversion of MW to kW) = $24,381,750. See 2025 MPBs.
18 Capacity transactions are from FERC electronic quarterly reports downloaded from https://eqrreportviewer.ferc.gov/ and cleaned by CalCCA. Included transactions have California LSE as 7 Figure 2. Alternative Allocation of Unused Storage Achieves 23% Reserve Margin in September 2025
The Report states that “this incremental margin is not simply “excess” capacity, but represents additional contracted, deliverable resources that may provide value under conditions that exceed forecasted load.”19 This implies an intent to ensure reliability by making compliance exceedingly difficult and allowing the system to lean on LSEs that must procure excess RA to meet their SOD requirements, rather than through transparent and defined reliability standards.

The Commission is obligated through Public Utilities Code section 380(h)(4)20 to ensure that the RA program “can reasonably maintain a standard measure of reliability, such as a one-day-in-10- year loss-of-load expectation or a similarly robust reliability metric adopted by the commission...” The Commission should meet the objectives of section 380 by planning for pre-the buyer for delivery in September 2025 with a trade date between November 1, 2024, and July 31, 2025.

CalCCA sorted these transactions from highest to lowest price and summed the transaction cost for the highest priced transactions up to a cumulative capacity of 2,175 MW. 19 Report at 35.
20 All subsequent code sections cited herein are references to the California Public Utilities Code unless otherwise specified.
8 determined reliability targets established through the Commission’s loss-of-load expectation study process and planning reserve margin, rather than by imposing transactional barriers that force over-procurement.

Energy Division finds that the potential gains of hourly load obligation trading do not outweigh “risk of unintended consequences.”21 This is a red herring. Throughout the five years of discussing hourly load obligation trading, no party has been able to articulate an “unintended consequence” that CalCCA has not addressed.
22 If there are “unintended consequences” that
arise following the implementation of hourly load obligation trading, the Commission has the power to modify the rules to close any reliability or compliance gaps that may emerge. The Commission should not decline to adopt measures with demonstrated affordability benefits based upon undefined “unintended consequences.”
III. HOURLY LOAD OBLIGATION TRADING SHOULD BE ADOPTED TO

ALLOW LSES TO TRANSACT AT THE SAME GRANULARITY AS THE SOD

REQUIREMENTS
The Commission should adopt CalCCA’s proposal in R.23-10-011 to allow LSEs to transact load obligations on an hourly basis.23 Under existing rules, LSEs are restricted in how they can transact with other entities to ensure RA compliance. Adjustments to an LSE’s portfolio are limited to transacting a product for all hours it is available for the whole month, even though obligations are unique to each hour. This mismatch means LSEs must purchase more RA than they need to meet their obligations, creating artificial market scarcity and unnecessarily driving up RA demand (and prices). CalCCA’s proposal would provide LSEs with the flexibility to 21 Report at 7.
22 See California Community Choice Association’s Opening Comments on the Proposed Decision, R.23-10-011 (June 11, 2025).
23 See California Community Choice Association’s Proposals on Track 3, R.23-10-011 (Jan. 17, 2025) (CalCCA Track 3 Proposals), at 8-18.
9 transact load obligations at the hourly level in order to reduce costs to consumers. If RA requirements are set on an hourly basis, some or all of the products should be transactable on an hourly basis.

CalCCA’s analysis of 2025 year-ahead RA filings submitted in R.23-10-011 demonstrates significant affordability benefits to increasing the transactability of the RA SOD program.24 CalCCA expects that all LSEs would benefit from a load obligation trading structure and expects that transactions among investor-owned utilities, community choice aggregators (CCA), and electric service providers (ESP) would occur. The larger the market, the more efficient the outcome. Since its analysis of 2025 year-ahead RA filings, CalCCA has issued a Whitepaper, attached as Appendix A, further documenting the benefits of hourly trading by simulating competitive market trades between LSEs. CalCCA has also performed additional analysis on 2025 month-ahead RA showings from CCAs demonstrating that, averaged across five peak summer months, CCAs in aggregate, purchased about 540 MW more RA capacity each month than they would have needed had a mechanism like hourly load obligation trading been available.25 At the 2025 final RA MPB,
26 those excess purchases cost CCA consumers more than
$30 million in the summer of 2025. If the tight market conditions observed in the summer of 24 See CalCCA Track 3 Proposals, at 8-11.
25 To quantify the excess RA capacity that could have been avoided with hourly load obligation trading, CalCCA first calculated the amount of thermal capacity each individual CCA could have sold from their final month-ahead portfolio, while still remaining compliant. To perform this calculation, CalCCA adjusted the way that an individual CCA would show its contracted storage capacity such that it maximized the amount of thermal capacity that could be removed. Next, CalCCA aggregated all CCA portfolios and requirements, and recalculated the excess thermal capacity from the aggregate showing.

The aggregation is a proxy for what could be achieved through frictionless trade between LSEs, which is enabled through a policy like hourly load obligation trading. Finally, the excess RA capacity that could be avoided through hourly load obligation trading was calculated as the difference between the excess of the aggregate and the excess for individual CCAs. On average across the five peak months from May to September, CalCCA observed 540 MW of excess thermal capacity that could have been avoided with hourly load obligation trading.
26 See 2025 MPBs.
10 2024 arise again, as suggested by the Commission’s recommendation for additional procurement in R.25-06-019,27 demand for capacity and RA prices could rise again to the levels observed in 2024. The CCAs’ excess RA purchases valued at the 2024 RA prices described in CalCCA’s RA Whitepaper would cost CCA customers nearly $51 million. Using similar assumptions about the indirect price reduction effect from lowering RA demand and the potential benefit of hourly load obligation trading across all Commission-jurisdictional LSEs, CalCCA’s findings from the 2025 month-ahead RA data suggest hourly obligation trading could save all LSEs $144-$179 million each year. These savings could then directly improve affordability for ratepayers.

Throughout R.23-10-011, CalCCA thoroughly addressed all critical concerns with its proposal expressed by Energy Division and parties by: (1) explaining why existing trading mechanisms are insufficient for the SOD program; (2) proposing a potential guardrail that would limit the amount of load an LSE can trade (of which CalCCA expands upon below); and (3) addressing how penalties would apply to LSEs using load obligation trades that are found noncompliant.28 The proposal received support from a broad range of stakeholders, including LSEs, suppliers, ratepayer advocates, and environmental groups,29 and as described above, is supported by extensive analysis of cost benefits. For these reasons, the Commission should adopt hourly load obligation trading.
27 Administrative Law Judge’s Ruling Seeking Comments on Electricity Portfolios for 2026-2027 Transmission Planning Process and Need for Additional Reliability Procurement, R.25-06-019 (Sept. 30, 2025).
28 See California Community Choice Association’s Opening Comments on the Proposed Decision, R.23-10-011 (June 11, 2025).
29 See Opening Comments filed in R.23-10-011 on or about March 3, 2025: American Clean Power – California Opening Comments, at 15; Alliance for Retail Energy Markets Opening Comments, at 3; The Public Advocates Office at the California Public Utilities Commission (Cal Advocates) Opening Comments, at 10-11; Clean Energy Buyers Association Opening Comments, at 7; Center for Energy Efficiency and Renewable Technologies Opening Comments, at 3; California Environmental Justice Alliance Opening Comments, at 11- 12; Hydrostor, Inc. Opening Comments, at 9; Microsoft Corporation Opening Comments, at 12-13; and Shell Energy North America (US), L.P. Opening Comments, at 4-5. 11 IV. THE COMMISSION SHOULD INVEST IN SOFTWARE AND SYSTEMS TO

AUTOMATE THE RA VALIDATION PROCESS
Energy Division’s manual RA validation process may result in the Commission passing up significant efficiency improvements over concerns with the administrative effort they would add to existing processes. Currently, all LSEs submit to the Commission a RA showing in Excel on an annual and monthly basis. Over the 20-plus year history of the RA program, the Excel spreadsheet has grown to include 14 visible sheets, 18 hidden sheets (used to perform calculations and validations), six macros, and requires a 58-page user guide to navigate. Energy Division’s continued rejection of hourly transactability as an affordability measure appears largely driven by the fact that the existing RA compliance review processes are no longer sufficient to operate the SOD program. The RA program procures billions of dollars of capacity annually and carries strict fines that can be up to $26.64/kw-month. In addition, the program is a major component in grid reliability. With the program’s growing complexity, including hourly verification, customized storage showings by hour, and charging sufficiency verifications, the compliance program has outgrown spreadsheets. The RA program needs a more robust and user-friendly compliance program to evaluate RA showings quickly and effectively.

Continued reliance on spreadsheets for validation of an increasingly complex RA program should no longer be a barrier to the adoption of sound policy proposals. The Commission regularly authorizes millions of dollars of IT work for a variety of purposes; for example, Item 6 on the February 26, 2026, Consent Agenda contemplates a $2.6 million increase for improvements to the California Distributed Generation Statistics Website. Given the critical importance of the RA program – supporting both reliability and affordability -- the Commission should invest in tools to make the validation process more automated and manageable for Energy 12 Division staff. If the Commission’s existing budget is inadequate, CalCCA would gladly support any Budget Change Proposal for the IT funding necessary for this project.

V. IF THE COMMISSION DECLINES TO INVEST IN SYSTEMS TO AUTOMATE

THE RA VALIDATION PROCESS, IT SHOULD ADOPT TEMPORARY

GUARDRAILS TO AID IN ASSESSING COMPLIANCE
If the Commission foregoes these investments and is concerned with the amount of administrative effort this proposal would create, the Commission should adopt two temporary guardrails that would help keep validation efforts manageable. Then, the Commission should scope into the RA proceeding a process to revisit the necessity of these guardrails after a year of implementation.

First, on an interim basis, the Commission could set an initial trading limit of no more than 25 percent of an LSE’s compliance obligation, as proposed in CalCCA’s March 3, 2025, Opening Comments in R.23-10-011.30 Given this limit may prohibit the use of hourly load obligation trading by smaller LSEs, the Commission should also adopt a de minimis threshold allowing LSEs with RA requirements less than 200 MW to trade up to 50 MW of their obligation. Furthermore, if the Commission is concerned with the administrative burden of multiple layers of load obligation trades, the Commission can require that if an LSE purchases a load obligation trade and then sells it to another LSE, that sale will count towards that LSE’s 25 percent limit.

Second, if the Commission believes Energy Division will have administrative difficulties validating showings with hourly load obligation trades, then on an interim basis the Commission could require hourly load transactions to be shown five business days prior to the RA showings to provide Energy Division staff with additional time to validate the showings. This change is not 30 California Community Choice Association’s Opening Comments on the Assigned Commissioner’s Amended Scoping Memo and Ruling, R.23-10-011 (Mar. 3, 2025) at 10-11. 13 ideal because CalCCA anticipates hourly load obligation trades would be used to fill marginal deficiencies after first procuring resources to fill open positions. However, it would be worth pursuing if it enables hourly load obligation trades to be a feature of the RA program.

VI. CONCLUSION
CalCCA respectfully requests consideration of the proposals herein and looks forward to an ongoing dialogue with the Commission and stakeholders.

Respectfully submitted,
Leanne Bober,
Director of Regulatory Affairs and Deputy
General Counsel

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
March 3, 2026

APPENDIX A
TO
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S
TRACK 1 PROPOSALS ON TRANSACTABILITY ISSUES

EFFECTIVE MECHANISMS FOR SLICE-OF-DAY RA TRADING
April 24, 2025
Effective Mechanisms
for Slice-of-Day RA Trading
Andrew Mills1
April 24, 2025
1 Director of Data Analytics, California Community Choice Association. Email: [email protected]. Special thanks to Evelyn Kahl (CalCCA), Eric Little (CalCCA), Lauren Carr (CalCCA), Desik Somasundaram (CalCCA), Maren Wenzel (Silicon Valley Clean Energy), Frias Abu-Sneneh (CleanPowerSF), Geoffrey Ihle (Central Coast Community Energy), and John Newton (Ava Community Energy) for feedback and guidance on this analysis.
1 2

1. Introduction
California is in the first year of a new Slice-of-Day (SOD) resource adequacy (RA) program. In the new SOD program, Load Serving Entities (LSEs) must show a portfolio of resources that are sufficient to meet all 24-hours of a peak load day in each month of the year. Experience from the 2024 test year, in which LSEs submitted a non-binding SOD filing in parallel with their binding legacy filings for a single monthly RA product, shows many LSEs had resources that exceeded their RA obligations during the same hours when other LSEs were short.2 This dynamic – whereby some LSEs possess excess RA while others are short – suggests there are additional opportunities for trade that are currently unrealized due to regulatory barriers. At present, rules set by the California Public Utilities Commission (CPUC) only allow trade of resources at a monthly level, not individual hourly obligations. CalCCA has advocated for hourly obligation trading, noting that a program that assigns obligations on an hourly basis should allow trade on an hourly basis to reduce costs to consumers.3 This analysis quantifies the value of trade, contrasts trading in a SOD policy environment with trading in the more familiar legacy RA program, and demonstrates the advantages of hourly obligation trading.

In addition to the 24-hour obligation, a primary feature of the SOD program is 24-hour accreditation of resources. Conventional thermal powerplants, such as natural gas fired generators, geothermal, and biomass plants are generally accredited with constant generation over all 24 hours. Variable resources, like wind and solar, on the other hand, are accredited based on a technology and region-specific exceedance profile of generation on peak days.4 Storage accreditation is constrained by the storage power rating, energy storage capability, and availability of excess energy to charge storage on the peak day. Altogether, the value of a resource depends on its contribution to the LSE’s assigned RA obligation coupled with its interaction with other resources in the LSEs portfolio.

To quantify the potential benefits of hourly trading, we developed a tool to simulate competitive market trades between LSEs. In the simulations, we quantify the benefits of trade for both monthly resource trading, which is currently allowed by CPUC rules, and hourly obligation trading, which has not yet been authorized. Hourly obligation trading allows an LSE with excess resources to take on a portion of the obligation of another LSE in individual hours. We simulate monthly resource trading and hourly obligation 2 CPUC Energy Division, 2024. Report on Resource Adequacy Slice of Day Implementation and Year Ahead Showings. February. Available at: https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/resource-adequacy-homepage/resource-adequacy-compliance-materials/slice-of-day-compliance-materials/energy-division-report-on-ra-sod-implementation-and-year-ahead-showings.pdf 3 CalCCA 2024. California Community Choice Association’s Comments on Assigned Commissioner’s Scoping Memo and Ruling. January 17. Available at:
https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M524/K571/524571013.PDF 4 Exceedance profiles are set by the CPUC program rules across all variable resources and are not unique to LSEs or specific generators.
3 trading in the same manner with a broker announcing prices and LSEs responding with bids and offers for obligations in specific hours.

Broadly, the simulations are based on an intermediary, like a broker, announcing prices for SOD RA products and LSEs simultaneously responding with bids to buy or offers to sell RA products at the announced prices. The LSE bids and offers take into consideration the requirement that their portfolios meet their obligations in each hour.

The LSEs develop their bids and offers by minimizing their cost, net of any revenue from selling RA products.5 The broker matches bids and offers between participants with the goal of maximizing internal trading opportunities, or conversely, minimizing the amount of RA products that must be purchased from external sources to meet obligations. The broker’s objective includes taking advantage of favorable opportunities for LSEs to sell any excess resources, not needed by participants, to external markets. In an auction-like process, the broker continuously revises the announced prices and collects additional bids and offers from LSEs until settling on final prices and quantities that maximize the trading opportunities. LSEs then make bilateral trades at the designated prices and quantities. The final quantities and prices are equivalent to the solution of a centralized optimization, in which an intermediary uses each LSE’s obligation and resource portfolio to come to an optimal reallocation of resources between participants. In the case of a broker and LSE bidding process, however, the LSEs only announce responses to prices without needing to hand over their commercially sensitive RA filings to the intermediary.

The direct benefits for participants are the gains from trade – the difference between the LSEs’ costs before trade, in which they must purchase external RA products to meet their obligations on their own, and the costs after trade.6 The costs of internal trades across all participants nets to zero, since each purchase is met by an equivalent sale to another participant, such that the total gains from trade is simply the reduction in the need to purchase RA products from external sources and the revenue from selling excess resources to external markets. For these simulations, we assume that excess resources would be sold to utilities under the rules of the Western Resource Adequacy Program (WRAP),7 at prices that are only 1/10th of the assumed cost of RA products for California LSEs.8
5 We assume that all LSEs behave as cost-minimizing price-takers and do not consider any potential strategic bidding behavior that may impact prices in a non-competitive manner. 6 Our analysis is limited to the short-run gains from trade because we assume the initial LSE resource portfolios do not change depending on the policy environment. In the long run, LSEs may alter their procurement decisions depending on exposure to different trading environments. We ignore these potential long-run impacts when quantifying the gains from trade. 7 WRAP. 2024. Review of Preliminary, Non-Binding WRAP Regional Data for the Current Participating Footprint for the Summer 2025 and Advisory Data for the Summer 2028. January 31. https://www.westernpowerpool.org/private-media/documents/2024-1- 16_Webinar_Summer_2025_and_2028_Data_updated_2024-12-12.pdf 8 Because the WRAP program has not yet gone into effect, the volume of market-based capacity transactions outside of California is low, making it difficult to estimate the value of capacity outside of California. From the limited set of non-California capacity transactions, we see that recent capacity prices are on average lower than in California. Based on the thin volume and lower prices, we simply assume that sales of capacity outside of California would occur at a price of 1/10th of the price in California. We expect 4 Notably, trade between participants also provides indirect benefits to all California LSEs due to the reduction in demand for RA products. Reduced demand for RA products lowers the price of RA, which lowers the cost of meeting RA obligations to all California LSEs. The magnitude of the indirect benefits depends on the avoided external RA purchases by the participants, the price elasticity of RA products, and the quantity of RA bought at market prices by California LSEs. Reducing the cost of RA in California has grown in importance in recent years following the rapid increase in RA prices.

While the weighted-average price for RA was $2.77/kW-mo in 2019,9 tight market conditions10 caused the weighted-average price to rise by a factor of nine to $26.26/kW-mo in 2024.11 The ability for trade to reduce the cost of RA has significant affordability implications for all of California.

To compare trading in the new SOD program with trading in the legacy RA program, we also simulate resource and obligation trading with a single monthly RA product. In the legacy RA program, resource accreditation is based on an effective load carrying capability (ELCC) and obligations are based on the highest demand in each month.

Although a broker is used to coordinate trading in the legacy RA program simulations, the broker is not strictly necessary. LSEs that are long could simply match with LSEs that are short and trade directly, resulting in the same outcome as with a broker.

Hourly obligation trading offers a similar opportunity for LSEs simply matching long and short hours without an intermediary to coordinate trades. We call hourly obligation trading without an intermediary “uncoordinated hourly obligation trading,” because this simple matching does not consider inter-temporal coupling nor the potential economic benefits of selling excess resources to external markets. An analogous uncoordinated approach for resource trading would be to only match LSEs that have excess thermal capacity with LSEs that are short in any hour.12 We call the simple matching of LSEs with excess thermal and LSEs that are short on thermal resources “uncoordinated resource trading”. We compare the effectiveness of uncoordinated trading to coordinated trading within the new SOD program.

The simulation results that follow are based on the confidential SOD RA filings for a subset of California LSEs, 24 community choice aggregators (CCAs), for the 2024 test non-California markets for RA to become more robust in the future with the implementation of WRAP, enabling better estimates of market prices.
9 CPUC. 2019. Calculation of the 2019 True Up and Forecast 2020 Market Price Benchmarks for the Power Charge Indifference Adjustment. R. 17-06-026. November. Available athttps://webproda.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/community-choice-aggregation-and-direct-access/2019-final-calculation-of-the-pcia-market-price-benchmarks.pdf 10 CalCCA. 2024. California’s Constrained Resource Adequacy Market:

Ratepayers Left Standing in a Game of Musical Chairs. January. : Available at: https://cal-cca.org/wp-content/uploads/2024/02/CalCCA-Stack-Analysis-2023-2026-updated-01_16_24-.pdf 11 CPUC. 2025. Market Price Benchmark Calculations 2024 (Revised). November. Available at https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/community-choice-aggregation-and-direct-access/2024-market-price-benchmarks-revised-20241105.pdf 12 Presumably other resources or bundles of resources could be chosen as the resource to trade in an uncoordinated fashion. We chose thermal resources for the simplicity of being able to quantify how much excess or how much shortage of thermal resources an LSE has. An LSE is long on thermal by the amount the aggregate resource showing exceeds their obligation in the tightest hour. An LSE is short on thermal by the amount the aggregate showing is less than their obligation in the hour with the greatest deficit. 5 year and the first binding year of 2025. The 2025 filings are “year-ahead” filings in which the obligations were set at 90% of the final requirements for the operating month. To quantify the gains from trade, we scaled the year-ahead obligations to the full 100% requirements and, in effect, ask how much of the remaining RA purchases for each CCA could be met through trade with other CCAs instead of going out to the market to buy incremental RA from external sources.

2. Results and Discussion

2.1 Trade Between CCAs Creates Substantial Value
Across the five summer months in 2025, simulated trading between CCAs directly reduces costs to participants by $60 million per year13 and the reduced demand for RA products produces $50 million per year in indirect benefits to all Californians.

2.1.1 Direct Benefits
For 2025, over 85% of the direct benefits of trade are from the reduced purchases of RA products from external sources while the remaining 15% are from the sales of excess resources to external markets. The gains from trade occur primarily in the months of July, August, and September when loads are highest and the accreditation of variable resources is lowest (see Figure 1).

The June gains from trade are also lower due to lower prices for external RA products in June compared to later months. The gains from trade are zero in May because each of the CCAs could meet their obligations on their own, obviating the need to purchase external RA even before trade, and the lack of a binding requirement for WRAP utilities in May.

The gains from trade in the June and September 2024 test-year filings are similar to the gains from trade in the corresponding month of the 2025 binding year. One exception is that sales of excess RA in September 2024 were near zero because the participating CCAs did not have sufficient resources to meet the obligations on their own, even after trade (see Table 1). As a result, some CCAs needed to purchase incremental RA from external sources even after trading with other CCAs. 13 The direct benefits of trade are proportional to the avoided purchases of external RA (or increased sales of external RA in cases with a net excess) and the assumed price of external RA. The external RA prices in this analysis are based on observed sales of capacity to California LSEs reported in FERC Electronic Quarterly Reports, as described in Section 5.3. Actual external RA prices faced by LSEs are uncertain, though the direct benefits would increase or decrease commensurate with changes in the external RA prices.
6 Note: Further details of gains from trade for September 2024 and 2025 are in Table 1 and Table 2, respectively. Gains from trade in all months are described in Appendix C.

Figure 1. Total gains from trade across all 24 CCAs with the 2024 test-year and 2025 year-ahead Slice-of-Day filings, with either resource trading (Resource: SOD) or hourly obligation trading (Obligation: SOD).

Gains from trade with uncoordinated trading, without an intermediary to coordinate trades, is shown by the wide, hatched bar.

2.1.2 Indirect Benefits
The $50 million per year in indirect benefits stem from the reduced demand for external RA products after trade and the downward pressure that places on RA prices.

Across the five summer months of 2025, trade reduces purchases of RA from external sources by 455 MW on average. Based on our observations of the average RA price and the net surplus from year to year,14 we estimate that average RA prices decrease by $1/kW-mo for every 1 GW demand reduction.15 In 2024, California LSEs purchased roughly 20 GW of RA products at market prices in each summer month.16 Altogether, trade between CCAs lowers demand for RA products and reduces costs for all California LSEs (CCAs, ESPs, IOUs, and POUs).
14 CalCCA. 2024. California’s Constrained Resource Adequacy Market: Ratepayers Left Standing in a Game of Musical Chairs. January: Available at: https://cal-cca.org/wp-content/uploads/2024/02/CalCCA-Stack-Analysis-2023-2026-updated-01_16_24-.pdf 15 Estimating the sensitivity of RA prices to shifts in RA demand is particularly challenging because of the bilateral nature of the California RA market. We describe our approach for estimating the sensitivity of RA prices to RA demand in Appendix B.
16 CalCCA analysis of FERC EQR capacity transactions downloaded from https://eqrreportviewer.ferc.gov/. 7 2.1.3 Benefits Would Grow if Participants Extended Beyond CCAs While trade between the 24 CCAs creates substantial direct and indirect benefits, the benefits would be even greater if trades occurred between all CPUC-jurisdictional entities (CCAs, ESPs, and IOUs). The CPUC’s analysis of 2024 test-year SOD filings17 identified short positions that were about 70 percent greater than the short positions of CCAs alone. Based on this finding, we estimate that trade between all CPUC-jurisdictional LSEs could reduce RA demand by 70 percent more than trade between CCAs. The greater reduction in RA purchases and further downward pressure on RA prices could increase the benefits of trade to more than $180 million per year ($105 million of direct benefits and $77 million of indirect benefits).

Scenario
Short Position (a.k.a.,
ExternalRA INC)
Gains from
Trade ($M)
Internal Trades
Requires
Intermediary
Before
Trade (MW)
After Trade
(MW)
Volume
(MW) Count
Average
Connections
Monetary
Transfer ($M)
I. Resource: ELCC 467 0 12.3 467 22 1.9 1.2 No
II. Obligation: ELCC 467 0 12.3 467 22 1.8 1.2 No
III. Resource: SOD 926 269 17.3 2,642 185 15.4 23.4 Yes IV. Obligation: SOD 926 261 17.3 3,591 150 12.5 11.7 Yes III.* Uncoordinated
Resrc.: SOD 926 748 4.7 185 7 1.8 N/A No
IV.* Uncoordinated
Oblg.: SOD 926 645 7.2 4,654 122 10.2 N/A No
Table 1. Summary of trade between CCAs across policy environments with September 2024 test-year data Scenario
Short Position (a.k.a.,
ExternalRA INC)
Gains from
Trade ($M)
Internal Trades
Requires
Intermediary
Before
Trade (MW)
After Trade
(MW)
Volume
(MW) Count
Average
Connections
Monetary
Transfer ($M)
I. Resource: ELCC 541 0 15.1 541 22 1.9 1.4 No
II. Obligation: ELCC 541 0 15.1 541 22 1.8 1.4 No
III. Resource: SOD 727 0 21.5 3,500 167 13.9 6.7 Yes
IV. Obligation: SOD 727 0 21.4 8,062 163 13.6 2.4 Yes
III.* Uncoordinated
Resrc.: SOD 727 182 14.2 561 16 1.9 N/A No
IV.* Uncoordinated
Oblg.: SOD 727 27 18.1 6,613 120 10.0 N/A No
Table 2. Summary of trade between CCAs across policy environments with September 2025 binding-year data

2.2 With an Intermediary, Resource Trading and Hourly Obligation Trading Achieve the Same Benefits
In the simulations of trade, the broker coordinates trades between LSEs, ensuring that any opportunity for an LSE to meet its obligations by purchasing RA products from a 17 CPUC Energy Division, 2024. Report on Resource Adequacy Slice of Day Implementation and Year Ahead Showings. February. Available at: https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/resource-adequacy-homepage/resource-adequacy-compliance-materials/slice-of-day-compliance-materials/energy-division-report-on-ra-sod-implementation-and-year-ahead-showings.pdf 8 participant is realized, without adversely affecting the other LSEs ability to meet its own obligations or to sell to an external market if more lucrative. LSEs participate by responding to broker-announced prices with bids and offers of RA products at quantities that are both feasible, in the sense that the LSE’s obligations will be met if the bids and offers are accepted, and minimize costs to the LSE. With this sophisticated trading mechanism, trading either resources or hourly obligations achieve roughly the same reduction in purchases of external RA and the same gains from trade, Figure 1.

Later sections discuss important differences between resource trading and hourly obligation trading, in terms of differences in internal monetary transfer between participants in Section 2.4 and ability to trade without the need for an intermediary in Section 2.5, but in terms of aggregate benefits, the two policy environments produce similar direct and indirect benefits.

2.3 Benefits of Participation are Widespread, Though Uneven For a participant, the most salient question is whether it benefits from trade, not necessarily the aggregate benefits to all participants. We find that all participants are economically better off by participating in the coordinated trades than on their own.

Individual CCA gains from trade across the five summer months of 2025 are quantified in Figure 2, shown as a percentage of the LSEs’ maximum cost if they met all of their RA obligations by buying RA from external sources (ExternalRA INC). We normalize the individual gains from trade in this manner to remove the effect of CCA size on the individual LSE gains from trade.

While all participants benefit from trade, some LSEs benefit more than others. For the summer months of 2025, roughly half of the participants reduce compliance costs by 10-30% through trade, while the remaining half see less than 5% reductions in cost.

The only contributor to gains from trade with uncoordinated trading are the avoided costs of purchasing RA from external sources (ExternalRA INC). This is because the way we simulate uncoordinated trading does not involve internal monetary transfer and does not involve sales of RA to external markets (ExternalRA DEC). Therefore, the only beneficiaries from uncoordinated trading in the simulations are LSEs that are short prior to trade.

Comparison of the beneficiaries of trade with uncoordinated and coordinated resource or hourly obligation trading in Figure 2 reveals that the LSEs that benefit the most from trade in 2025 are those that are short prior to trade. LSEs that are long prior to trade see proportionally smaller benefits from selling RA products internally or to external markets. The relatively low benefits to participants that are long prior to trade is in part due to low internal RA prices in the summer of 2025 resulting from coordinated trades eliminating the short positions of all participants even in September 2025 (see Table 2). In contrast, internal RA product prices remain high in September 2024, when some participants still must purchase RA from external sources (ExternalRA INC) even 9 after trade (see Table 1), and therefore LSEs that are long prior to trade see proportionally higher benefits from trade.18
Figure 2. Aggregate direct benefits across May to September 2025 for each CCA, scaled by the CCA’s maximum RA cost if it met all obligations at the assumed external RA price.

2.4 Hourly Obligation Trading Targets Periods with Scarce Resources Even though the simulations show that hourly obligation trading and resource trading yield similar gains for participants, we observe important differences between the two policy environments. One difference is the way that hourly obligation trading directs internal monetary transfer toward hours that are most constrained in aggregate.

With the September 2024 test-case data, trade reduced the need to purchase RA products from external sources (ExternalRA INC), but it did not eliminate it entirely (see Table 1). We illustrate differences in internal monetary transfer in this constrained month by showing the trade volume and final prices with resource trading and hourly obligation trading for September 2024 in Figure 3. The product of the trade volume for the internal RA product and its corresponding price sums to the total internal monetary transfer. The product of external RA volume and prices, in contrast, is the post-trade external RA cost which is minimized by the broker by coordinating trades.

Final prices for internal RA products from the broker auctions differ across resources or hours, for policy environments that allow resource trading or hourly obligation trading, respectively, depending on how much another increment of that product 18 Relatively low benefits of trade for LSEs that are long prior to trade raises the question of whether these entities would participate in trade. We find that even if LSEs that are long prior to trade decide to abstain from trade, there continue to be trading benefits for the LSEs that are short prior to trade. The direct benefits of trade when only short LSEs participate are $20-21 million in 2025, which is 42-44% of the gains the short participants would have realized if all of the LSEs were to participate. 10 would reduce the need to buy RA from external sources (ExternalRA INC). With hourly obligation trading, the only hour with a final non-zero price was hour ending 19 (HE19). In all other hours the final price for hourly obligations was zero because participating LSEs could easily take on additional obligations in hours other than HE19 without triggering the need to buy additional RA from external sources. Even though hourly obligation trading involves a large volume of internal trades, the final auction price of zero for hourly obligations in most hours results in monetary transfers being concentrated only in the subset of trades involving obligations in HE19.

With resource trading, on the other hand, final prices are non-zero for all RA products, meaning that every internal trade also requires an internal monetary transfer between participants. The internal monetary transfer is largest for trades involving natural-gas fired thermal resources, unspecified imports, and 4-hour batteries. Prices for wind and solar resources are lower and therefore contribute less to the internal monetary transfer even though the internal trade volume is large. For some participants, favorable trades involve selling one high-cost resource, such as a battery, while simultaneously buying a high-cost resource with different characteristics, such as a thermal resource, to marginally lower the participant’s net cost. Such a trade involves a large internal monetary transfer yet only contributes a small amount to the overall gains from trade. Similar transactions were not required in the policy environment with hourly obligation trading.

Figure 3. Comparison of SOD trade volume and price using September 2024 test-year data with the resource (top) and obligation (bottom) trading policy
11 2.5 Slice-of-Day Trading is 6-9 Times More Complex
Gains from trade are not unique to the new SOD RA program. Even with the legacy RA program, where different resources would be converted to a comparable RA product with a single qualifying capacity value through an accreditation factor called the ELCC, LSEs that are long can benefit from selling excess RA to LSEs that are short. What is unique to the SOD RA program is the complexity of trades required to achieve the benefits. Overall, we estimate SOD trading to be 6-9 times more complex than trading with the legacy RA program.

We quantify the complexity of internal trade through three related metrics: volume, transaction count, and average number of connections.19 These metrics are shown for each of the policy environments with September 2024 test-year data and September 2025 binding data in Table 1and Table 2, respectively. In the legacy RA program, every internal trade results in a comparable reduction in the short position of the purchasing LSE meaning that the trade volume is equal to the reduction in short positions before and after trade. In contrast, trading with SOD products across the summer months of 2025 requires an internal trade volume that is nine times the reduction in purchases of external RA. The count of transactions with SOD trading is more than 6 times the count of transactions in the legacy RA policy environment, where a unique transaction is the bundle of all RA products sold by one LSE to another. Finally, the average number of trading partners with SOD trades is 6 times more than in the legacy RA policy environment.

To illustrate the complexity of SOD resource trading, we visualize the trading network between 24 CCAs and external sources of RA using September 2024 test-year data, Figure 4. Each node represents a CCA, with the size of the bubble proportional to the CCA’s transaction costs (price times quantity). Each edge of the network is a transaction involving a particular type of RA resource, with arrows showing the direction from seller to buyer and the width of the arrow based on the transaction cost.

Even though the volume of wind and solar RA product trades is large, the low prices for these products leads to smaller transaction costs and less prominent edges. 19 As is common in any optimization-based simulation, numerical issues can sometimes lead to trades with very small quantities being included in the final allocation, impacting metrics such as transaction count and number of trading partners. For these two metrics, we exclude any transaction with a quantity below

0.5 MW in the tally of transaction count and trading partners. 12 Note: Bubbles are CCAs, sized based on transaction costs. Lines are transactions sized by transaction cost.

Figure 4. Visualization of trading networks in the SOD resource trading policy environment using September 2024 test-year data

2.6 Hourly Obligation Trading Allows Simple Trades without an Intermediary
With the increased complexity of SOD trading, it is important for policy makers to provide LSEs with tools necessary to simplify trade to manage the risk that LSEs forgo trading and instead purchase additional unnecessary external RA products, at the expense of ratepayers. Previous results demonstrated that hourly obligation trading can achieve the same benefits as resource trading when an intermediary is available to coordinate trades (Sections 2.2) and that hourly obligation trading can target hours where aggregate resources of participants are insufficient to meet the aggregate obligation (Section 2.4). One more potential advantage of hourly obligation trading is that it provides a pathway for LSEs to achieve some of the same benefits of coordinated trades without the need for an intermediary. In the simplest form, participants that show resources in excess of their obligations in some hours can take on the obligations of LSEs that are short in those hours. Trades made in this manner, without further consideration of impacts on storage charging energy or impacts to opportunities to sell excess to external markets, is what we call uncoordinated hourly obligation trading and is illustrated for September 2024 and 2025 in Figure 5. For the 13 summer months of 2025, even the uncoordinated trades achieve 80% of the gains from trade observed with a sophisticated intermediary to coordinate trades (see Figure 1). (a)
(b)
Figure 5. Comparison of uncoordinated and coordinated hourly obligation trades when CCAs have (a) a net deficit of resources in September 2024 or (b) a net surplus of resources in September 2025.

The uncoordinated approach is not always as effective, however. With the September 2024 test-year some of the participants still need to purchase RA products from external sources, even after trades coordinated by an intermediary. For this month, the uncoordinated hourly obligation trading only achieved 35% of the gains of trade possible with an intermediary. In this case, the intermediary helps to find trading opportunities involving HE19 that come from adjusting storage charging, storage discharge, and obligations of LSEs to better align with overall needs. The possibility of these adjustments to generate gains from trade is not evident with uncoordinated hourly obligation trading alone, as shown in Figure 5a.

In months where long positions exceed short positions in all hours, as in the September 2025 filings, there are again differences in trading opportunities identified 14 by uncoordinated hourly obligation trading and with an intermediary to coordinate trades, as in Figure 5b. However, the differences are much less impactful on the gains from trade since trades from both approaches can largely eliminate the need to purchase RA from external sources. Allowing hourly obligation trading opens a pathway for LSEs to begin to realize the benefits of trade without the need to develop a novel sophisticated intermediary to coordinate trades.

3. Practical Considerations for Implementing Trading
Mechanisms
The previous results are based on simulations comparing alternative policy environments. Moving from simulation to real-world implementation would require a much more in-depth investigation. Here we describe some of the important practical considerations but note that much more work on this question remains.

Three different mechanisms for SOD trading have been mentioned in this analysis: (1) a centralized optimization; (2) a broker running an auction; and (3) uncoordinated trades. First, a centralized optimization across all participating LSEs involves an intermediary having access to each LSEs confidential resource portfolio and obligations then using that information to reallocate resources an optimal manner. Second, a broker running an auction-like process would involve LSEs responding to announced prices with bids and offers. While both mechanisms lead to the same solution and gains from trade, under the auction approach, the LSEs can maintain the confidentiality of their portfolios and obligations. Finally, even an uncoordinated form of trade could achieve significant benefits without requiring an intermediary. In this case, trading could be as simple as participating LSEs posting hourly bids and offers to a bulletin board and making bilateral trades from there. Although this would not achieve all the benefits available with an intermediary, it would still maintain confidentiality and would be simple to implement. These high-level considerations are summarized in Table 3.

Centralized
Optimization
Broker Running an
Auction
Posting Hourly
Obligation Bid/Offers
to a Bulletin Board
LSEs keep contracts
confidential No Yes Yes
Achievable without
intermediary No No Yes
Maximizes trading
opportunities Yes Yes No
Table 3. Comparison of slice-of-day trading mechanisms
15 4. Conclusions
Hourly obligation trades can create substantial value. In the five summer months of 2025, simulated trading between the 24 CCAs could provide as much as $60 million per year in direct benefits from avoiding the need to buy incremental RA from external sources and even enabling sales of excess resources to external markets. The benefits of trade are widespread across all participants, though CCAs that are short prior to trade benefit more than CCAs that are long. Furthermore, the trade between CCAs lowers overall demand for RA products. Lower demand reduces RA prices for all California LSEs, creating a collective indirect benefit of $50 million per year.

With some form of sophisticated intermediary to coordinate trades, resource and hourly obligation trading can both achieve these benefits. An advantage of hourly obligation trading is that it requires only 2/5 of the internal monetary transfer between participants yet achieves the same benefits of resource trading. If part of the justification for the SOD program is a fair allocation of the costs of maintaining a reliable system, hourly obligation trading is better suited to valuing hours of the day with scarcity at the aggregate level.

Implementing an effective trading mechanism with the SOD program will not be easy.

Trading in the SOD policy environment is 6-9 times more complex than that of the legacy monthly RA product. It will require a greater volume of trades, more transactions, and more trading partners. Achievement of the full benefits of trade requires a much more sophisticated coordination mechanism than participants might be accustomed to. Hourly obligation trading allows for simple trades without an intermediary, while still achieving 80% of the benefits.

With rapidly rising electricity costs in California, all ratepayers would benefit from having more flexibility in the way RA obligations are met. Trade is important and fundamentally more complex in the new SOD program. Policy makers should support the development of effective trading mechanisms that go hand in hand with the transition to SOD. Otherwise, the SOD RA program will drive up costs for consumers with no direct benefit to reliability.
16 5. Methods and Data

5.1 Policy Environments and ExternalRA
We developed a common analysis approach to compare trading under four different policy environments: two with RA based on a single monthly product where resources are accredited by an ELCC and two based on the SOD accreditation. With either ELCC or SOD accreditation, we compare resource trading and obligation trading, Table 4.

Accreditation

ELCC SOD
TradingProduct
Resources I: Resource trading
with ELCC
III. Resource trading with SOD
Obligations II. Obligation trading
with ELCC
IV. Hourly obligation trading with SOD
Table 4. Four policy environments in RA trading analysis The trading analysis is based on a simulation of LSEs each having obligations and resources characterized in a regulatory filing for the CPUC called an RA filing. All participants in the trade are CPUC jurisdictional and subject to common RA program rules. Any RA obligations that are not met by internal trades with participants or any short positions prior to trade are met through incremental purchases of RA from external sources (ExternalRA INC), Figure 6. Assuming transmission capacity is available, the source of external RA can be from any resource in the western interconnection, whose reliability is assured by the Western Electricity Coordinating Council (WECC). We assume that purchases of ExternalRA INC contribute to a participant’s portfolio similar to an unspecified resource available 24-hours a day (Unspecified|24X24). All ExternalRA INC is purchased at a single price, varying only by month of the year.

Figure 6. Illustration of the relationship of ExternalRA INC and DEC to participants in trade 17 In cases where an LSE’s resources exceed its obligations, it may also be able to sell that excess to an external market (ExternalRA DEC). We assume that the purchaser of external RA would be an entity in WECC that has an RA requirement but is not CPUC jurisdictional. This assumption allows us to set a single price for external sales each month. An LSE that sells a resource to an external market removes the resource from its portfolio and converts it to ExternalRA DEC using the ELCC factors applicable to the external market.

The primary driver of the gains from trade is the reduction in purchases of ExternalRA across all participants before and after trade. Figure 7 illustrates how purchases of internal RA products can reduce the need to purchase ExternalRA across all four policy environments.

Figure 7. Illustration of the effect of trade on the need to purchase ExternalRA in each of the four policy environments

5.2 Trade Simulation
The Broker and LSE Bidding Strategy models are derived from a Central Optimization Problem in which the costs of meeting all LSE obligations are minimized, as in an RA pool. In the Central Optimization, a planner uses its visibility into the obligations and resources of every participating LSE to reallocate RA products (either resources or obligations, depending on the environment), such that the residual need to purchase RA products from an external source (ExternalRA INC), is minimized.

5.2.1 Central Optimization Problem
At a high level, the Central Optimization Problem is formulated as follows:

Central Optimization Problem:

Minimize: ExternalCosts + TradeFriction
18 Subject To:

ExcessDemandp = 0, for each p in set of internal RA Products Deficitl = 0, for each l in the set of participating LSEs ExternalRAINC
l <= Max_Deficit_Prior_to_Tradel, for each l in set of LSEs Where:

ExternalCosts = ExternalRAINC* ExternalRAINC_Price – ExternalRADEC* ExternalRADEC_Price TradeFriction = Σp(InternalPurchasep + InternalSaleI)*UnitFrictionCost ExcessDemandp = InternalPurchasep – InternalSalep
The disadvantage of the Central Optimization is that each participant must share information about its full portfolio of RA contracts and its RA obligation with the entity operating the optimization. Such information is confidential and commercially sensitive, potentially limiting the set of LSEs willing to participate.

5.2.2 Decomposition to Broker and LSE Bidding
An alternative is to have an independent broker operate an auction-like process where it announces prices and participants respond with bid/offer quantities at those prices.

The broker revises prices and continues to collect bids until it can balance supply and demand for RA products between participants while maximizing the gains from trade.

The Broker/LSE Bidding Strategy models arise from a Dantizg-Wolfe Decomposition of the Central Optimization Problem.20 The Broker is equivalent to the master problem and the LSE Bidding Strategy is part of the subproblem. The decomposition yields an equivalent solution to the Central Optimization, though it is solved through an iterative process rather than a single optimization.21 More importantly, the Broker needs to only collect bid/offer responses from LSEs and does not need confidential information on each LSE participant’s resource contracts or obligations.22 Broker:

Minimize: Σr((ExternalCostr+TradeFrictionr)*weightr)
20 Conejo, A.J., Castillo, E., Minguez, R. and Garcia-Bertrand, R., 2010. Decomposition Techniques in Mathematical Programming: Engineering and Science Applications. Springer Science & Business Media. 21 The use of Dantizg-Wolfe decomposition to model coordinated markets has been used elsewhere in the literature, e.g., Najafi, F. and Fripp, M., 2023. “Market-based Coordination of Price-responsive Demand Using Dantzig-Wolfe Decomposition Method”. Energy and AI, 14, p.100277. https://doi.org/10.1016/j.egyai.2023.100277
22 The code used to create the simulations of trade in all policy environments is available at:
https://github.com/CalCCA-Data-Team/agent_based_ra_market 19 Subject To:

Σr (weightr) = 1
Σr(ExcessDemandr,p*weightr) <= 0, for each p in the set of internal RA products LSE Bidding Strategy:

Minimize: ExternalCostl + TradeFrictionI + InternalCostl Subject To:

Deficitl = 0
ExternalRAINC
l <= Max_Deficit_Prior_to_Tradel,
Where:

InternalCostl = Σp (InternalRA_product_pricep*(Internal_RA_boughtp,l- Internal_RA_soldp,l))

5.2.3 LSE Bidding
In each round of the auction, LSEs respond to the Broker’s prices with bids to purchase or offers to sell RA products. The bid/offers include both internal RA and external RA (INC or DEC) products. The LSE chooses bid/offers that minimize its cost of eliminating deficiencies. We further assume that LSEs will not purchase more ExternalRA_INC during trade than they would have had to purchase before trade. In other words, for LSEs that were already in compliance with RA requirements before trade, their ExternalRA_INC bids will always be zero.

Figure 8. Illustration of LSE bidding either resources (top) or hourly obligations (bottom) in response to prices announced by the broker
20 Figure 8 illustrates the process of a broker announcing prices for RA products and an LSE responding with bids to purchase or offers to buy the RA products at those prices.

The LSE’s bids and offers are made with the expectation that all bids and offers will be successful. In other words, there is no risk that an LSE offers to sell a product and then their bids for other RA products are unmet causing a deficiency. As described next, an important role of the broker is to collect all feasible bids and offers at different price points, then coordinate trades based on a final determination of quantities and prices that maintains feasibility for each participating LSE.

5.2.4 Broker Auction
In every auction round, r, the Broker finds weights to place on previous rounds to minimize costs, while ensuring that supply and demand for internal RA products are balanced. The shadow value of the supply and demand balance constraint for each product, representing the marginal reduction in total costs from another unit of supply, sets the prices for next round of the auction.23 The Broker continues the auction process until the Broker finds no further opportunity to reduce total costs. More precisely, the auction is completed when the weighted sum of all external RA costs matches the sum of the costs across all LSEs in the most recent auction round.24 The final allocation of trades is based on applying the final weights to the bids collected in previous auction rounds. LSEs trade RA products with the other participants at the final auction prices. An example of the history of RA product prices and the convergence of external costs with the sum of LSE costs across auction rounds is shown in Figure 9.
23 To begin the auction process, the Broker first collects bids based on randomly chosen prices. Bids in response to random prices are used to initialize the model. After initializing, all subsequent prices are from the shadow value of the supply and demand balance constraint in the Broker problem. 24 We continue until the gap is less than 0.05% of the total costs across LSEs. 21 Note: UB is upper bound and LB is lower bound as defined in the Dantizg -Wolfe decomposition by Conejo et al (2010).

Figure 9. Example of auction process using September 2024 test-year data

5.2.5 Bilateral Matching
The broker tells participants their final quantity of RA product purchases and sales along with announcing final prices. Participants then bilaterally trade these products with other participants at the specified prices. We randomly match sellers of an RA product with buyers of a product, setting the transaction quantity to the lower of the bid or offer. Any residual quantity is again randomly matched with another buyer or seller in the list of participants. The bilateral matching ends when the final quantities specified by the broker are met.

5.3 Data and Assumptions

5.3.1 Slice-of-Day RA Filings
All data used in this analysis is from the confidential SOD RA filings provided by the 24 CCA members of CalCCA to the CPUC. The June and September 2024 filings were test-year filings that were not binding. The May-September 2025 filings were the year-ahead binding filings submitted to the CPUC at the end of October 2024. CalCCA preserves all confidential information and reports only anonymized or aggregate results that mask the original filer.
22 5.3.2 LSE Portfolio and Obligations
The SOD RA filings contain the confidential hourly obligations and the contracts with resources to meet the obligations. With the 2024 test-year filings, we use the obligations directly provided in the CCA filing. In the 2025 year-ahead filings, however, CCAs are only required to demonstrate sufficient resources to meet 90% of the operating month’s obligation. To determine how much more resources CCAs must procure between the year-ahead filing and the operating month, we scale the obligation in the YARA filing to the full 100% obligation.

We characterize the CCA’s portfolio based on the contracted nameplate capacity of each technology type, accounting for regional variation in resource portfolios. We also extract the 24-hour profile the CCA uses for each non-storage contract. For storage contracts, we ignore the profile and instead dispatch the storage within the LSE bidding process based on power, energy capacity, and charging sufficiency constraints.

5.3.3 Slice-of-Day RA Product Definitions
The 24-hour profiles often vary across CCA filings, even for the same technology type.

To simplify the analysis, we create standard RA product definitions with common profiles and parameters. The standard hydro RA product, for example, is the contracted-capacity weighted average of all hydro profiles across the CCAs (varying only by hour and month, but not by CCA). Similarly, we group batteries by duration (1, 2, 4, or 8 hour) and then use the weighted-average efficiency and duration for the standardized product. For Unspecified resources, we group them by the average capacity factor into three standard buckets: 5X24, 16X24, and 24X24. Within each of these buckets we use the capacity-weighted average profile.

5.3.4 Legacy Monthly RA
Data from the CCAs’ SOD filings are also used in create the parameters necessary for simulating trade in the legacy RA program. We estimate each CCA’s monthly RA obligation as the maximum hourly obligation. We estimate the monthly RA portfolio by converting the contracted nameplate to contracted net qualifying capacity using the 2024 technology factors by technology and month reported by the CAISO.25

5.3.5 External RA INC Prices
We estimate the cost of purchasing RA from external sources based on the recently observed capacity-weighted average price of RA sold to California LSEs during the period between the year-ahead filings (October 31, 2023) and the final RA filing date 45 days before the start of the operating month. CalCCA collects and cleans public RA transaction data from FERC Electronic Quarterly Reports. Assumed prices for purchases of external RA (ExternalRA INC) in each month are listed in Table 5. Because FERC EQR data only reports historical prices, we assume the same prices for analysis of both the 2024 test-year and 2025 binding year filings.
25 CAISO. 2024. Final Net Qualifying Capacity for Compliance Year 2024.Available at:
https://www.caiso.com/documents/final-net-qualifying-capacity-report-for-compliance-year-2024.xlsx 23 Month Weighted-average RA
price ($/kW-mo)
May 11.7
June 13.2
July 21.1
August 25.5
September 26.0
Table 5. Assumed prices for purchases of RA from external sources (ExternalRA INC)

5.3.6 External RA DEC Prices and ELCC factors
We assume that sales of excess resources to external markets would be based on the conversion of the nameplate capacity to an external RA product based on the ELCC factors announced by WRAP.26
Few sales for RA products to non-California loads are reported in the FERC EQRs, especially for the period between the year-ahead filing and operating month. Rather than set the price for sales of RA to external markets based on this thin volume of transactions, we instead assume that the price for ExternalRA DEC is 1/10th of the price of External RA INC, reported in Table 5.
26 WRAP. 2024. Review of Preliminary, Non-Binding WRAP Regional Data for the Current Participating Footprint for the Summer 2025 and Advisory Data for the Summer 2028. January 31. https://www.westernpowerpool.org/private-media/documents/2024-1- 16_Webinar_Summer_2025_and_2028_Data_updated_2024-12-12.pdf 24 Appendix A. Sensitivity of Gains from Trade to Changes in Portfolio Composition
Across California, LSE portfolios are transitioning toward a greater share of renewables and storage and away from thermal generation. In 2019, 67% of the resources shown for compliance with September resource adequacy compliance were from natural gas-fired generation and unspecified imports, while less than 0.2% was from battery storage. By 2024, the share of RA from natural gas and unspecified imports dropped to 56% while the share from energy storage and hybrid plants increased to over 17% of the September showings.27 Pathways to achieving greenhouse gas emission reduction goals associated with California’s SB 100 policy continue the trend of adding energy storage and reducing reliance on natural-gas generation.28 This transition of the LSE portfolios impacts the gains from trade.

To quantify the impact, we evaluate the September 2025 gains from trade as thermal capacity is swapped out with 4-hour duration battery storage capacity, Figure 10. Prior to trade, we ensure replacement of thermal capacity with 4-hour battery does not worsen the LSE’s maximum deficits by increasing the size of the replacement 4-hour battery when needed. As more of the thermal capacity is replaced, the size of the replacement battery relative to the thermal capacity also grows to maintain the same level of pre-trade compliance. We cap the ratio of replacement 4-hour battery to thermal capacity at 4:1. We therefore allow maximum pre-trade deficits to increase if it would otherwise require more than a 4:1 ratio of replacement 4-hour battery to thermal capacity.
27 CAISO Historical Resource Adequacy Aggregate Data as of January 22, 2025:
https://www.caiso.com/documents/historicalresourceadequacyaggregatedata.xlsx 28 CEC 2021 SB 100 Joint Agency Report, Achieving 100 Percent Clean Electricity in California: An Initial Assessment https://efiling.energy.ca.gov/EFiling/GetFile.aspx?tn=237167&DocumentContentId=70349 25 (a) (b)
Figure 10. Sensitivity of September 2025 Gains from Trade to LSE Portfolio Composition with (a) SOD Resource Trading and (b) SOD Obligation Trading.

Modest shifts in the LSEs’ portfolios from thermal capacity to 4-hour battery capacity of up to 25% of the original thermal capacity, have little impact on the gains from trade with both resource trading and obligation trading. After about 25% of the thermal capacity is replaced, however, the gains from trade rapidly decline. By the time all thermal capacity is replaced with 4-hour batteries, the gains from trade are only 10% of the gains with the original portfolio.

Changes in the internal prices of RA products with shifts in the portfolio composition help explain the reasons for the decline in the gains from trade. With the original portfolios, the aggregate accreditation of the resources in the LSE portfolios exceeded the aggregate obligations, allowing trades between LSEs to offset the need to purchase external RA. After about 20% of the thermal capacity is replaced by storage, the price of RA from thermal resources jumps to the level of the price of purchasing ExternalRA INC, indicating the aggregate surplus relative to obligations has disappeared. At this point trade between participants continues to be as high as with the original portfolios, though as thermal capacity is further removed, the ability for 4-hour battery storage to 26 meet obligations begins to decline. At 20% reduction in thermal capacity, the price of solar and other sources of charging energy increases, and the price of hourly obligations outside of the traditional early evening peak net load hours also starts to increase. The broadening of hours where energy is needed to meet obligations reduce the diversity across LSEs and lowers the potential trading opportunities.

Future changes to the composition of LSE portfolios are uncertain. However, replacing 25% of the thermal resources by 4-hour battery storage would likely take multiple years. In the interim, mechanisms to enable trading between LSEs will continue to provide benefits comparable to the levels calculated with 2025 portfolios. 27 Appendix B. Calculating the Indirect Benefits of Reduced RA Demand
Mechanisms to enable trade between LSEs lowers demand for RA products from the external RA market. Lower demand for RA puts downward pressure on RA prices, indirectly lowering the costs of RA for all California LSEs. A general framework for quantifying these sorts of benefits to consumers comes from the "Demand Response Induced Price Reduction" or DRIPE that is used in Northeastern states as part of their evaluation of the costs and benefits of demand-side measures.29 At a conceptual level, this indirect benefit of trade is illustrated in Figure 11. Small reductions in prices can create significant consumer savings when consumers purchase a large volume at market prices.

Figure 11. Illustration of the indirect benefits of trade from lower RA market prices The indirect benefits are the area of the red rectangle. The height of the rectangle depends on the sensitivity of RA prices to RA demand (represented as E) and the reduction in RA demand attributable to trade (represented as D). The width of the rectangle is the volume of RA purchases that see the lower price due to decreased RA demand (represented as Q). Indirect benefits of trade are therefore E*D*Q.

One important caveat is that from an economic perspective, the price reduction effect is often seen as a transfer between suppliers and consumers rather than a net welfare 29 State and Local Energy Efficiency Action Network (2015). State Approaches to Demand Reduction Induced Price Effects: Examining How Energy Efficiency Can Lower Prices for All. Prepared by: Colin Taylor, Bruce Hedman, and Amelie Goldberg from the Institute for Industrial Productivity under contract to Oak Ridge National Laboratory. Available at: https://www.energy.gov/sites/default/files/2021-07/SEEAction-DRIPE.pdf 28 gain. From a consumer perspective, however, lower prices do make consumers better off at least in the short run. In addition, the California Public Utilities Commission recently suggested that high prices in the RA market are due in part to the exercise of market power.30 Under non-competitive market conditions, mechanisms that provide additional pathways for trade between participants can mitigate suppliers’ ability to raise prices. Lowering prices through increasing the competitiveness of markets can create a net increase economic welfare by reducing the deadweight loss associated with non-competitive behavior.31
The most uncertain parameter is the sensitivity of RA prices to RA demand (E). To estimate the price sensitivity, we compare the weighted-average price of RA sold to California LSEs in September to our estimate of the net supply in September for the California resource adequacy market for 2019 to 2024. The net supply is based on an RA stack analysis which compares the available supply of RA to the demand for RA using the legacy capacity accreditation approach based on ELCC factors.32 As a coarse approximation, the sensitivity of RA price to RA demand is estimated as the slope of simple regression across these data points. The resulting slope of -1.0, seen in Figure 12, represents a decrease in the weighted-average RA price of $1.0/kW-mo for every GW decrease in RA demand (E = $1.0 kW/mo per GW).

Figure 12. Approximation of sensitivity of RA prices to RA demand using September data from 2019-2024 The reduction in RA demand resulting from trade (D) is a direct result of our analysis of the CCA’s 2025 year-ahead RA filings for the months of May through September, with 30 Energy Division Staff Report of the 2024-2025 Resource Adequacy Market Price Benchmark (Feb., 26, 2025). Available at: https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M557/K608/557608990.PDF 31 For an example of deadweight loss arising from non-competitive behavior in California electricity market see Borenstein, S., Bushnell, J.B. and Wolak, F.A., 2002. Measuring market inefficiencies in California's restructured wholesale electricity market. American Economic Review, 92(5), pp.1376-1405. 32 CalCCA. 2024. California’s Constrained Resource Adequacy Market: Ratepayers Left Standing in a Game of Musical Chairs. January. : Available at: https://cal-cca.org/wp-content/uploads/2024/02/CalCCA-Stack-Analysis-2023-2026-updated-01_16_24-.pdf 29 obligations scaled to 100% the final obligations. Across the five summer months, we find that trade between CCA lowers demand for external RA (ExternalRA INC) by roughly 500 MW per month (D = 0.5 GW per mo). Additional details on the reduction in demand for external RA with trade in each month are provided in Appendix C.

Finally, we estimate the volume of RA that would be purchased at lower prices due to the reduction in RA demand (Q). This is again a difficult number to quantify with precision. We observe RA purchases by California LSE's of about 20 GW of capacity products on average across summer months in the FERC EQR dataset (Q = 20 GW each month).

Altogether, the indirect benefits of trade between the CCAs (E*D*Q) total approximately $50 million per year.
30 Appendix C. Gains from Trade in All Months
Table 1 and Table 2 detail the gains from trade across different policy environments using data from September 2024 and 2025. For completeness, we present the calculations for all months in Table 6.

Scenario
Short
Position
(a.k.a.,
ExternalRA
INC) Gains
from
Trade
($M)
Internal Trades
Month and Year
Before
Trade
(MW)
After
Trade
(MW)
Volume
(MW) Count
Average
Connections
Monetary
Transfer
($M)
June 2024 I. Resource: ELCC 258 0 3.7 257 20 1.8 0.3
II. Obligation: ELCC 258 0 3.7 257 21 1.9 0.3
III. Resource: SOD 433 0 6.9 2,921 124 10.3 2.4
IV. Obligation: SOD 433 0 6.9 5,632 172 14.3 0.5
III.* Uncoordinated Resrc.: SOD 433 123 4.1 321 21 1.8 N/A IV.* Uncoordinated Oblg.: SOD 433 6 5.6 3,752 112 9.3 N/A September 2024 I. Resource: ELCC 467 0 12.3 467 22 1.9 1.2 II. Obligation: ELCC 467 0 12.3 467 22 1.8 1.2
III. Resource: SOD 926 269 17.3 2,642 185 15.4 23.4
IV. Obligation: SOD 926 261 17.3 3,591 150 12.5 11.7
III.* Uncoordinated Resrc.: SOD 926 748 4.7 185 7 1.8 N/A IV.* Uncoordinated Oblg.: SOD 926 645 7.2 4,654 122 10.2 N/A May 2025 I. Resource: ELCC 31 0 0.3 31 3 1.0 0.0
II. Obligation: ELCC 31 0 0.3 31 2 1.0 0.0
III. Resource: SOD 5 5 0.0 0 0 0.0 0.0
IV. Obligation: SOD 5 5 0.0 0 0 0.0 0.0
III.* Uncoordinated Resrc.: SOD 5 0 0.1 5 3 1.2 N/A
IV.* Uncoordinated Oblg.: SOD 5 0 0.1 14 7 1.8 N/A
June 2025 I. Resource: ELCC 289 0 5.7 288 20 1.8 0.4
II. Obligation: ELCC 289 0 5.7 288 20 1.8 0.4
III. Resource: SOD 252 0 6.2 2,325 158 13.2 2.3
IV. Obligation: SOD 252 0 6.2 4,244 155 12.9 0.6
III.* Uncoordinated Resrc..: SOD 252 0 3.3 263 15 1.4 N/A IV.* Uncoordinated Oblg.: SOD 252 1 3.3 1,923 87 7.3 N/A July 2025 I. Resource: ELCC 590 0 13.4 590 23 1.9 1.2
II. Obligation: ELCC 590 0 13.4 590 23 1.9 1.2
III. Resource: SOD 674 0 16.4 2,255 177 14.7 4.2
IV. Obligation: SOD 674 0 16.3 8,201 171 14.2 1.8
III.* Uncoordinated Resrc.: SOD 674 83 12.5 616 20 1.9 N/A IV.* Uncoordinated Oblg.: SOD 674 49 13.1 6,297 134 11.2 N/A August 2025 I. Resource: ELCC 480 0 13.3 480 23 1.9 1.2 II. Obligation: ELCC 480 0 13.3 480 23 1.9 1.2
III. Resource: SOD 623 0 18.0 3,620 128 10.7 6.5
IV. Obligation: SOD 623 0 17.9 7,564 181 15.1 2.3
III.* Uncoordinated Resrc.: SOD 623 163 11.7 478 22 1.9 N/A IV.* Uncoordinated Oblg.: SOD 623 40 14.8 4,839 127 10.6 N/A September 2025 I. Resource: ELCC 541 0 15.1 541 22 1.9 1.4 II. Obligation: ELCC 541 0 15.1 541 22 1.8 1.4
III. Resource: SOD 727 0 21.5 3,500 167 13.9 6.7
IV. Obligation: SOD 727 0 21.4 8,062 163 13.6 2.4
III.* Uncoordinated Resrc.: SOD 727 182 14.2 561 16 1.9 N/A IV.* Uncoordinated Oblg.: SOD 727 27 18.1 6,613 120 10.0 N/A Table 6. Summary of trade between CCAs across policy environments with data from all months

CALIFORNIA COMMUNITY CHOICE ASSOCIATION
1121 L Street, Suite #400, Sacramento, CA 95814
[email protected] | cal-cca.org
March 3, 2026

VIA ELECTRONIC MAIL
Energy Division
California Public Utilities Commission
505 Van Ness Avenue
San Francisco, CA 94102
Email: [email protected]
Re: California Community Choice Association’s Comments on Draft Resolution E-5440 - Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric Remediation Plans for Integration Capacity Analysis Dear Energy Division,
Pursuant to Rule 14.5 of the California Public Utilities Commission (Commission) Rules of Practice and Procedure,1 and the accompanying Cover Letter to the February 11, 2026, Draft Resolution E-54402(Draft Resolution) approving, with modifications, the Investor-owned Utilities’ (IOU)3 Integration Capacity Analysis (ICA) remediation plans and baseline reporting, California Community Choice Association4(CalCCA) submits these comments on the Draft Resolution.

I. INTRODUCTION
CalCCA appreciates the Commission’s continued efforts to improve the reliability and usefulness of the ICA. Decision (D.) 24-10-030 states that “the ICA quantifies the maximum amount of power that can be injected into, or drawn from, the distribution system while requiring 1 State of California Public Utilities Commission, Rules of Practice and Procedure, California Code of Regulations Title 20, Division 1, Chapter 1 (May 2021). 2 Draft Resolution E-5440 Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric Remediation Plans for Integration Capacity Analysis (Feb. 11, 2026). 3 The IOUs as referred to herein are Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric Company (SDG&E). 4 California Community Choice Association represents the interests of 24 community choice electricity providers in California: Apple Valley Choice Energy, Ava Community Energy, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance of Southern California, CleanPowerSF, Desert Community Energy, Energy For Palmdale’s Independent Choice, Lancaster Energy, Marin Clean Energy, Orange County Power Authority, Peninsula Clean Energy, Pico Rivera Innovative Municipal Energy, Pioneer Community Energy, Pomona Choice Energy, Rancho Mirage Energy Authority, Redwood Coast Energy Authority, San Diego Community Power, San Jacinto Power, San José Clean Energy, Santa Barbara Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power, and Valley Clean Energy.

Energy Division
CalCCA Comments on Draft Resolution E-5440
March 3, 2026

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CALIFORNIA COMMUNITY CHOICE ASSOCIATION
1121 L Street, Suite #400, Sacramento, CA 95814
[email protected] | cal-cca.org
minimal to no distribution mitigations, upgrades, or operational restrictions.”5 Up-to-date ICA results that are aligned with engineered values provide customers and developers with valuable information for siting and designing new load and generation. While the Draft Resolution addresses many shortcomings of the IOUs’ proposed ICA Remediation Plans, it does not go far enough in requiring the IOUs to implement essential measures to ensure ICA data is complete and aligned with engineered values. Specifically, the Commission should modify the Draft Resolution to:
• Strengthen the requirements for aligning the ICA results with engineered values, including:
o Shortening the timeline for IOUs to file an Advice Letter (AL) proposing a methodology to address misalignment between ICA and engineered values; and
o Requiring SCE to file an AL proposing near-term fixes for the Load ICA. • Strengthen the requirement for the monthly ICA refresh of changed circuits (monthly refresh), including:
o Changing the language in the Draft Resolution from “the IOUs should strive to update all triggered circuits every month” to “the IOUs must update all triggered circuits every month;”
o Establishing criteria for exceptions from meeting the monthly refresh requirement;
o Establishing a reporting requirement for violating the monthly refresh; and o Establishing an enforcement mechanism for repeated violations of the monthly refresh.
• Require SDG&E to cease over-redacting ICA data fields unless SDG&E provides specific evidence that the data violates the 15/15 Rule.6

II. THE COMMISSION SHOULD STRENGTHEN THE REQUIREMENTS FOR

ALIGNING THE ICA RESULTS WITH ENGINEERING VALUES
The Commission should revise the Draft Resolution to strengthen the requirements for aligning the ICA results with engineered values. The IOUs have been unable to consistently produce usable and dependable Load and Generation ICA values, rendering those values unreliable. While the Draft Resolution takes steps to enhance tracking and reporting to improve 5 D.24-10-030, Decision Adopting Improvements to Distribution Planning and Project Execution Process, Distribution Resource Planning Portals, and Integration Capacity Analysis Maps (Oct. 23, 2024), at 8.
6 See Draft Resolution, at 5, Footnote 12 (defining the 15/15 Rule as a “data set containing at least 15 customers with no customer receiving no more than 15 percent of the load.”).

Energy Division
CalCCA Comments on Draft Resolution E-5440
March 3, 2026

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CALIFORNIA COMMUNITY CHOICE ASSOCIATION
1121 L Street, Suite #400, Sacramento, CA 95814
[email protected] | cal-cca.org
ICA usability, it should adopt the following recommendations as it does not go far enough in requiring timely ICA improvements and fails to specifically address SCE’s Load ICA shortcomings.

First, the Commission should shorten the timeline for IOUs to file a joint AL proposing a methodology to address misalignment between ICA and engineered values. The Draft Resolution defines alignment as “the degree to which ICA results reflect the engineering outcomes of actual interconnection or energization applications, as determined by the distribution engineer processing those applications,” referring to the latter as the engineered value.7 The Draft Resolution then establishes requirements for the IOUs to track and report on scenarios in which the ICA and engineered values are aligned (concordant) or misaligned (discordant) to understand the root causes of any misalignment and determine corrective action. However, the Draft Resolution gives the IOUs between 18 and 30 months to file a joint AL proposing ICA improvements to address discordance.

While the ICA discordance tracking and reporting requirements are new, the misalignment between ICA and engineered values is a longstanding issue that has been reported in the IOUs’ Biannual ICA Reports and discussed during quarterly ICA workshops. Providing the IOUs 18 to 30 months to submit an AL recommending improvements could delay implementation of measures to correct discordance by three or more years. The Commission should revise the timeline for filing the joint AL to between six and 12 months to ensure the timely resolution of the longstanding ICA misalignment issues.

Second, the Commission should require SCE to file an AL to propose near-term fixes for the Load ICA. The protests of the Interstate Renewable Energy Council (IREC)8 and the Public
Advocates Office of the California Public Utilities Commission (Cal Advocates) 9 detail known
issues affecting the usability of SCE’s ICA values, including the high number of circuits with zero Load ICA hosting capacity. The Draft Resolution fails to address this issue and instead focuses on tracking and reporting on ICA misalignment. The issue of SCE’s high number of circuits with zero Load ICA has been a longstanding and well-documented concern and should be addressed in the Draft Resolution. The Commission should therefore require SCE to file an AL within 60 days of the adoption of the Draft Resolution describing how it will ensure that the Load ICA values align with engineering values and address the zero Load ICA issue. 7 Draft Resolution, at 16.
8 See IREC’s Protest of Utility Companies’ ALs – PG&E AL 7686-E (ICA Remediation Plan); SDG&E AL 4710-E (Addressing Remediation Plan for ICA), and SCE AL 5614-E (ICA Remediation Plan) – Filed in Compliance with D.24-10-030 (Sep. 15, 2025), at 3-12. 9 See Cal Advocates’ Protest to SCE’s Tier 3 AL 5614-E, PG&E’s Tier 3 AL 7686-E, and SDG&E’s Tier 3 AL 4710-E: Integration Capacity Analysis Remediation Plans Pursuant to D.24-10-030 (Sept. 15, 2025), at 5-6.

Energy Division
CalCCA Comments on Draft Resolution E-5440
March 3, 2026

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CALIFORNIA COMMUNITY CHOICE ASSOCIATION
1121 L Street, Suite #400, Sacramento, CA 95814
[email protected] | cal-cca.org
III. THE REQUIREMENT FOR THE MONTHLY ICA REFRESH OF CHANGED

CIRCUITS SHOULD BE STRENGTHENED
The Commission should revise the Draft Resolution to strengthen the requirements for the monthly refresh of ICA for changed circuits. The ICA values for individual circuits change as new customer load and generation come online, requiring the IOUs to refresh these values for affected circuits. The Draft Resolution agrees with IREC and Cal Advocates that the ICA results for changed circuits must be updated monthly.10 However, the Draft Resolution states that the IOUs “should strive to update all triggered circuits every month,” and acknowledges exceptions that may prevent the monthly refresh.11 Further, the Draft Resolution does not propose any enforcement measures if an IOU repeatedly fails to meet the monthly refresh requirement.

Without a specific requirement for IOUs to refresh ICA values on changed circuits, along with specific criteria for exceptions and a means to enforce compliance, the ICA values may not provide meaningful value to customers or developers. The Draft Resolution should be modified to address these concerns.

First, the language in the Draft Resolution should be revised to state that the IOUs “must update all triggered circuits every month,” rather than the IOUs merely “should” provide the update. This removes ambiguity and conveys the necessity of monthly refreshing of the ICA values. Requiring a monthly refresh will provide clarity around the age of ICA values, significantly improving the usability of the maps. Second, the Draft Resolution should be revised to provide guidance on handling exceptions that prevent refreshing ICA values. This could include adjusting the refresh timing relative to model runs to minimize exceptions due to model run times, so that only circuits triggered a certain number of days in advance of a refresh are included. Finally, the Draft Resolution should include a specific requirement for the percentage of changed circuits to be refreshed monthly, reporting requirements for the IOUs to explain deviations from this requirement, and penalties for continued failure to meet this criterion.

IV. THE COMMISSION SHOULD REQUIRE SDG&E TO CEASE REDACTING ALL ICA FIELDS THAT COMPLY WITH THE 15/15 RULE
The Commission should revise the Draft Resolution to require SDG&E to cease over-redacting ICA data that do not reveal customer data. The Draft Resolution agrees with IREC and Cal Advocates that “SDG&E has failed to comply with Commission requirements for redaction methods for ICA” consistent with the 15/15 Rule for protecting customer information.12 The Draft Resolution correctly identifies “Load Profile” and “Op Gen Flex” as data fields that could reveal customer information, yet it only directs SDG&E to cease redacting the “Total Generation” and “Existing Generation” data fields. However, SDG&E is redacting data fields that do not reveal customer information, including the “Integration Capacity NO Operational Flexibility” and “Integration Capacity” fields. These additional data fields provide necessary 10 Draft Resolution, at 14.
11 Id. (emphasis added)
12 Id.

Energy Division
CalCCA Comments on Draft Resolution E-5440
March 3, 2026

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CALIFORNIA COMMUNITY CHOICE ASSOCIATION
1121 L Street, Suite #400, Sacramento, CA 95814
[email protected] | cal-cca.org
information for customers siting electric vehicle charging and other new loads or generation. The Draft Resolution should be modified to limit SDG&E’s redaction to only data fields that reveal customer information consistent with the 15/15 Rule.

V. CONCLUSION
CalCCA appreciates the Commission’s thoughtful and careful consideration of these comments.

Respectfully submitted,

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
Leanne Bober,
Director of Regulatory Affairs and
Deputy General Counsel
cc via email:

[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
Service List: R.21-06-017

BEFORE THE PUBLIC UTILITIES COMMISSION

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
1121 L Street, Suite 400
Sacramento, CA 95814
Telephone: (510) 980-9459
E-mail: [email protected]
March 3, 2026
i

1 Acronyms used herein are defined in the body of this document.

BEFORE THE PUBLIC UTILITIES COMMISSION

II. THE REPORT DIMINISHES THE PROBLEMS WITH SOD AND DOES NOT

ADDRESS THE CORE AFFORDABILITY ISSUE HOURLY LOAD

ALLOW LSES TO TRANSACT AT THE SAME GRANULARITY AS THE SOD

V. IF THE COMMISSION DECLINES TO INVEST IN SYSTEMS TO AUTOMATE

THE RA VALIDATION PROCESS, IT SHOULD ADOPT TEMPORARY

VI. CONCLUSION
CalCCA respectfully requests consideration of the proposals herein and looks forward to an ongoing dialogue with the Commission and stakeholders.

Respectfully submitted,
Leanne Bober,
Director of Regulatory Affairs and Deputy
General Counsel

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
March 3, 2026

APPENDIX A
TO
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S
TRACK 1 PROPOSALS ON TRANSACTABILITY ISSUES

2. Results and Discussion

Gains from trade with uncoordinated trading, without an intermediary to coordinate trades, is shown by the wide, hatched bar.

2.1.2 Indirect Benefits
The $50 million per year in indirect benefits stem from the reduced demand for external RA products after trade and the downward pressure that places on RA prices.

0.5 MW in the tally of transaction count and trading partners. 12 Note: Bubbles are CCAs, sized based on transaction costs. Lines are transactions sized by transaction cost.

Figure 4. Visualization of trading networks in the SOD resource trading policy environment using September 2024 test-year data

Implementing an effective trading mechanism with the SOD program will not be easy.

Accreditation

Figure 7. Illustration of the effect of trade on the need to purchase ExternalRA in each of the four policy environments

5.2.1 Central Optimization Problem
At a high level, the Central Optimization Problem is formulated as follows:

Central Optimization Problem:

Minimize: ExternalCosts + TradeFriction
18 Subject To:

ExcessDemandp = 0, for each p in set of internal RA Products Deficitl = 0, for each l in the set of participating LSEs ExternalRAINC
l <= Max_Deficit_Prior_to_Tradel, for each l in set of LSEs Where:

The broker revises prices and continues to collect bids until it can balance supply and demand for RA products between participants while maximizing the gains from trade.

Σr (weightr) = 1
Σr(ExcessDemandr,p*weightr) <= 0, for each p in the set of internal RA products LSE Bidding Strategy:

Minimize: ExternalCostl + TradeFrictionI + InternalCostl Subject To:

Deficitl = 0
ExternalRAINC
l <= Max_Deficit_Prior_to_Tradel,
Where:

InternalCostl = Σp (InternalRA_product_pricep*(Internal_RA_boughtp,l- Internal_RA_soldp,l))

Figure 9. Example of auction process using September 2024 test-year data

5.3 Data and Assumptions

5.3.3 Slice-of-Day RA Product Definitions
The 24-hour profiles often vary across CCA filings, even for the same technology type.

MCE Board of DirectorsMarch 19, 2026

MCE Board of Directors
March 19, 2026