Regulatory Packet — MCE Board of Directors, September 19, 2024 (part 2 of 2)

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

1. 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

2. 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

3. 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

4. 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

5. 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

6. 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

7. 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 2 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

8. 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

9. 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

10. 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

11. 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

12. 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

13. 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

Page 3 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

14. 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

15. 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

16. 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

17. 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

18. 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

19. 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

Page 4 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

20. 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

21. 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

22. 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

23. 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

24. 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

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

26. 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

Page 5 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

27. 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

28. 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

29. 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

30. 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

31. 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

32. 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

33. 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

Page 6 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

34. 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

35. 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

36. 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

37. 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

38. 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

39. 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

40. 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

41. 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

Page 7 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

42. 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

43. 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

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

45. 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

46. 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

47. 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

48. 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

49. 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 B
Select PG&E Responses to CalCCA Data Requests
DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_001-Q026 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
DCPP Extended Operations 2025 Forecast
Application 24-03-018
Data Response
PG&E Data Request No.: CalCCA_001-Q026
PG&E File Name: DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_001-Q026 Request Date: May 7, 2024 Requester DR No.: 001
Date Sent: May 21, 2024 Requesting Party: California Community Choice Association
PG&E Witness: Kristin Manz Requester: Corey Cochran
QUESTION 026
Referring to PG&E’s prepared testimony, page 9-8, lines 6-33: Provide the following:
a. Does PG&E intend to use the volumetric performance fee revenue to make improvements to its generating assets (either PG&E-owned or contracted)? b. If so, please describe which assets would be improved with this revenue, including identifying whether any of the assets are PCIA-eligible resources. c. Does PG&E plan to make any improvements which would extend the life of any PG&E-owned or contracted generating assets? If so, please explain.

ANSWER 026
PG&E proposes to use a portion of the DCPP volumetric performance fees to accelerate enhancements to the asset management, inspection, and maintenance activities associated with its utility-owned hydro generation facilities. These activities are aimed at reducing operational and system risk. The activities are expected to increase the resiliency and reliability of the assets, rather than extend the life of the assets. PG&E’s hydro facilities are PCIA-eligible resources.

DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_001-Q027 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
DCPP Extended Operations 2025 Forecast
Application 24-03-018
Data Response
PG&E Data Request No.: CalCCA_001-Q027
PG&E File Name: DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_001-Q027 Request Date: May 7, 2024 Requester DR No.: 001
Date Sent: May 21, 2024 Requesting Party: California Community Choice Association
PG&E Witness: Ryan Stanley Requester: Corey Cochran
QUESTION 027
Referring to PG&E’s prepared testimony, pages 10-4 through 10-5 and PG&E’s Application at page 10: Please describe when during the true-up process interested parties will have an opportunity to review and audit actual costs and revenues from the previous year, including the accounting treatment of those costs and revenues.

ANSWER 027
D.23-12-036 Ordering Paragraph 4 generally accepted PG&E’s proposed ERRA-like process to authorize forecast DCPP extended operation costs and subsequent true-up to actual costs and market revenues. Consistent with the mandate provided in Public Utilities Code Section 712.8(h)(1), the subsequent true-up process occurs via “an expedited Tier 3 advice letter process, provided that there shall be no further review of the reasonableness of costs incurred if actual costs are below 115 of the forecasts costs.” Section 712.8(h)(1) and D.23-12-036 do not contemplate an audit of these costs.1
Pursuant to Section 712.8(h)(1), costs in excess of 15 percent above PG&E’s approved annual DCPP extended operations forecast application would be subject to a reasonableness review.
1 See Pub. Util. Code § 712.8(h)(1) as quoted above. See D.23-12-036, COL 59.

DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_001-Q028 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
DCPP Extended Operations 2025 Forecast
Application 24-03-018
Data Response
PG&E Data Request No.: CalCCA_001-Q028
PG&E File Name: DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_001-Q028 Request Date: May 7, 2024 Requester DR No.: 001
Date Sent: May 21, 2024 Requesting Party: California Community Choice Association
PG&E Witness: Ryan Stanley Requester: Corey Cochran
QUESTION 028
Referring to PG&E’s prepared testimony, pages 10-4 through 10-5 and PG&E’s Application at page 10: Will interested parties have an opportunity to review and audit actual costs and revenues from the previous calendar year during a Tier 3 Advice Letter process, or will that opportunity occur as a part of a forecast proceeding? Please explain.

ANSWER 028
As part of the Tier 3 advice letter process, parties may issue discovery requests in a manner that is consistent with the Commission’s best practices for discovery. However, to the extent that CalCCA assumes that the Tier 3 advice letter process adopted by the Commission mirrors the audit of recorded entries that occurs in the annual Energy Resource Recovery Account (ERRA) Compliance Review proceeding, the requirements set forth under Senate Bill 846 do not mandate a review and audit of actual costs and revenues1 and as recognized by D.23-12-036.2
In response to this question, PG&E assumes opening a new CPUC action will be unnecessary as long as recorded costs do not exceed 115 percent of the adopted forecast.
1 Please refer to PG&E’s response to Question 27 of this request and Public Utilities Code Section 712.8(h)(1).
2 Please refer to PG&E’s response to Question 27 of this request and D.23-12-036, COL 59.

DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_001-Q029 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
DCPP Extended Operations 2025 Forecast
Application 24-03-018
Data Response
PG&E Data Request No.: CalCCA_001-Q029
PG&E File Name: DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_001-Q029 Request Date: May 7, 2024 Requester DR No.: 001
Date Sent: May 21, 2024 Requesting Party: California Community Choice Association
PG&E Witness: Ryan Stanley Requester: Corey Cochran
QUESTION 029
Referring to PG&E’s prepared testimony, pages 10-4 through 10-5 and PG&E’s Application at page 10: Does PG&E plan to provide detailed workpapers regarding its actual costs and revenues as a part of the annual true-up process? ANSWER 029
Please refer to PG&E’s responses to Questions 27 and 28 of this data request. As Section 712.8(h)(1) of the Public Utilities Code and Decision 23-12-036 do not contemplate an audit as part of the true-up process for costs that do not exceed 115 percent of the original cost forecast, PG&E intends to limit workpapers for the Tier 3 advice letter process to a summarized level. However, as also noted, amounts exceeding 115 percent of the approved DCPP cost forecast will be subject to a regulatory process.

DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002-Q003 Page 1 §PACIFIC GAS AND ELECTRIC COMPANY
DCPP Extended Operations 2025 Forecast
Application 24-03-018
Data Response
PG&E Data Request No.: CalCCA_002-Q003
PG&E File Name: DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002-Q003 Request Date: June 19, 2024 Requester DR No.: 002
Date Sent: July 5, 2024 Requesting Party: California Community Choice Association
PG&E Witness: Ryan Stanley Requester: Corey Cochran
QUESTION 003
Referring to PG&E’s response to CalCCA DR 1.29: Please describe the regulatory process PG&E is referring to in this response which DCPP costs exceeding 115 percent of the approved forecast will be subject to.

ANSWER 003
As part of the subsequent true-up process identified in Section 712.8(h)(1), PG&E proposed that the content of the annual expedited Tier 3 DCPP Extended Operations Costs True-Up advice letter be structured similarly to the review of procurement-related balancing accounts in the annual ERRA Compliance Review proceeding.1 Please see PG&E’s response to Question 6 of this data request for more specifics. Consistent with that process, PG&E intends to present all recorded costs—including if they are above 115% of the approved forecast in the Tier 3 advice letter, as well as analysis of the drivers—and seek Commission direction as to how it plans to conduct a reasonableness review if costs exceed 115% of the approved forecast.
1 See DCPP OIR, PG&E Testimony, Chapter 3, Page 3-12, Lines 15-28.

DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002-Q005 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
DCPP Extended Operations 2025 Forecast
Application 24-03-018
Data Response
PG&E Data Request No.: CalCCA_002-Q005
PG&E File Name: DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002-Q005 Request Date: June 19, 2024 Requester DR No.: 002
Date Sent: July 5, 2024 Requesting Party: California Community Choice Association
PG&E Witness: Ryan Stanley Requester: Corey Cochran
QUESTION 005
Referring to PG&E’s responses to CalCCA DR 1.27 - 1.29; Provide the following:
a. Please explain when the Tier 3 Advice Letter will be filed each year. b. When will the first Tier 3 Advice Letter be filed?
c. Please explain how and when the true-up will be rolled into rates.

ANSWER 005
PG&E responds as follows:
a. PG&E has not yet determined the exact timing it expects to submit its expedited Tier 3 Advice Letter for the annual true-up, other than it must come after the end of the prior calendar year. PG&E is assessing the appropriate timing of this filing and how to align it with the DCPP Forecast process to include any update in rates expeditiously.

However, as noted in PG&E’s Testimony in the DCPP OIR, it currently anticipates submitting an advice letter governing the first Test Year of extended operations on or before March 31, 2026, which would provide the appropriate time for disposition of a true-up or true-down amount to be reflected in the next Fall Update.1
b. Please see response to subpart a.
c. For purposes of PG&E’s cost recovery Application proposal, PG&E proposed that the actual expense project costs and O&M expenses that are at or below 115 percent of PG&E’s forecast costs be amortized in rates on January 1 of each year (via the DCPP Forecast proceeding) subject to any final review through General Order 96-B advice letter process (in the true-up).1 1 Please see PG&E’s Testimony, Chapter 3, Page 3-13, Lines 13-18.

DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002-Q006 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
DCPP Extended Operations 2025 Forecast
Application 24-03-018
Data Response
PG&E Data Request No.: CalCCA_002-Q006
PG&E File Name: DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002-Q006 Request Date: June 19, 2024 Requester DR No.: 002
Date Sent: July 5, 2024 Requesting Party: California Community Choice Association
PG&E Witness: Ryan Stanley Requester: Corey Cochran
QUESTION 006
Referring to PG&E’s response to CalCCA DR 1.29: Please explain further PG&E’s understanding regarding the review of costs during the Tier 3 Advice Letter Process.

Does PG&E anticipate review of the gross costs only, costs net of market revenue only, or something else?
ANSWER 006
As explained in response to Question 3 of this data request, PG&E proposed that the contents of the annual expedited DCPP Extended Operations Costs True-Up advice letter be structured similarly to the review of procurement-related balancing accounts in the annual ERRA Compliance Review proceeding, with disposition via a resolution of the Commission.1
Specifically, the presentation would: (1) describe the background and structure of the DCEOBA and the associated subaccounts, (2) describe activity recorded to the account and associated subaccounts, and (3) describe the variance analysis for PG&E’s forecasted costs compared to the actual recorded costs for the record period.

PG&E believes that the presentation of the activity in the expedited Tier 3 advice letter would include all activity in the DCEOBA, but that costs would be presented gross to properly review actual project costs and O&M expenses against the forecast. 1 See DCPP OIR, PG&E Testimony, Chapter 3, Page 3-12, Lines 15-28.

DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002-Q007 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
DCPP Extended Operations 2025 Forecast
Application 24-03-018
Data Response
PG&E Data Request No.: CalCCA_002-Q007
PG&E File Name: DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002-Q007 Request Date: June 19, 2024 Requester DR No.: 002
Date Sent: July 5, 2024 Requesting Party: California Community Choice Association
PG&E Witness: Ryan Stanley /
Conor Doyle
Requester: Corey Cochran
QUESTION 007
Referring to PG&E’s response to CalCCA DR 1.28; Provide the following regarding the DCPP forecast application filed in 2025:
a. Please explain will the DCEOBA account be strictly historical (i.e. recorded balance as of December 2024)?
b. Or will it be a projected balancing account balance (i.e. as projected by the end of December 2025)?
ANSWER 007
PG&E interprets this question to be asking whether the DCPP Forecast Application (starting in the second year) will follow the same conventions of the ERRA Forecast framework, whereby forecasted over and undercollections of the targeted balancing accounts at the end of the filing year (in this case, the 2025 DCEOBA balance) will be included in the revenue requirement request for the following year (in this case, the 2026 revenue requirement to collect in rates).

As noted in response to Question 3 of this data request, Ordering Paragraph 4 of Decision 23-12-036 generally accepted PG&E’s proposed ERRA-like process to authorized forecast DCPP extended operation costs and subsequent true-up to actual costs and market revenues.

As detailed by PG&E’s proposal in the DCPP OIR:

For the purposes of PG&E’s cost recovery Application proposal, PG&E proposes that actual expense project costs and O&M expenses that are at or below 115 percent of PG&E’s forecast costs be amortized in rates on January 1 of each year subject to any final review through the General Order 96-B advice letter process.1
Essentially, PG&E expects the 2026 revenue requirements for rates to include the forecast over or undercollection in the DCEOBA to the extent that actual expenses are 1 See DCPP OIR, PG&E Testimony, Chapter 3, Page 3-13, Lines 4-8.

DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002-Q007 Page 2 at or below 115 percent of PG&E’s forecast cost to be amortized in the next AET while recorded balances are still reviewed in the expedited Tier 3 true-up advice letter. This is much like projected over and undercollections in generation and procurement-related balancing accounts are presented in the ERRA Forecast today and still later reviewed in the ERRA Compliance proceeding; however, the key differences is amortizations included in the forecast will not exceed the 115 percent threshold.

DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002-Q012 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
DCPP Extended Operations 2025 Forecast
Application 24-03-018
Data Response
PG&E Data Request No.: CalCCA_002-Q012
PG&E File Name: DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002-Q012 Request Date: June 19, 2024 Requester DR No.: 002
Date Sent: July 12, 2024 Requesting Party: California Community Choice Association
PG&E Witness: Thomas R Baldwin Requester: Corey Cochran QUESTION 012
Referring to PG&E’s prepared testimony page 7-7, line 28, through page 7-8, line 17:

Please provide a list of each unplanned outage experienced at DCPP unit 1 or unit 2 over the last 10 years. For each outage, please provide the following:
a. Generating unit
b. Outage start date
c. Outage end date
d. Lost generation output (MWh)
e. Lost capacity (MW-month)
f. Replacement power costs
g. Description of the outage event, including root cause h. Whether the Commission determined that the unit was out of service as a result of a failure of the operator to meet the reasonable manager standard.

ANSWER 012
PG&E objects to this request on the grounds that CalCCA’s request is overly broad and outside the scope of the proceeding. Subject to and notwithstanding this objection, PG&E responds as follows. See Attachment 1 to this data response (see Excel, filename “DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002- Q012Atch01.xlsx”).

DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002-Q012Atch01.xlsx Generating
Unit Outage Start Date Outage End Date
Lost Generation
Output (MWh)
Lost Capacity
(MW-Month)*
Replacement
Power Cost Description of the outage event including root cause Did the Commission determine
that the unit was out of service as a
result of a failure of the operator
to meet the reasonable manager
standard?
1 6/25/13 22:37 7/2/13 14:17 178,348 244 $9,703,491 Socket weld failure from high cycle fatigue requiring unit shutdown to repair. No
2 7/10/13 9:50 7/14/13 1:42 97,796 134 $4,739,812
Lightning arrestor insulator arc resulting in unit trip during hot wash due to asymmetric contamination
deposition from environment No
1 3/16/14 20:20 3/27/14 3:22 275,936 378 $12,156,562
Reactor coolant pump 1-3 high seal leak-off flow due
to pump shaft misalignment to seal requiring unit
shutdown to repair. No
2 2/2/14 11:29 2/8/14 3:37 151,516 208 $10,689,742
Lightning Arrestor insulator arc resulted in unit trip
during light rain due to asymmetric contamination
deposition from environment No
2 8/14/14 23:30 8/18/14 17:34 100,244 137 $4,398,820
Manufacturer supplied diesel bolt broke due to high
cycle fatigue while a second diesel was out of service
for maintenance, thereby requiring unit shutdown per
operating license. Manufacturer instructions did not
provide adequate detail to preclude such failure. No
1 1/2/15 20:00 1/4/15 20:11 53,821 74 $1,797,741
Residual heat removal pipe weld failed due to vibration induced by containment fan cooler operation,
extending an unrelated planned maintenance outage
by two days to perform repairs. No
2 12/1/18 10:06 12/3/18 17:57 62,161 85 $1,836,765
California transmission grid event triggered a DCPP
switchyard protective scheme which caused the unit to
disconnect from the grid. No
2 2/13/20 15:18 2/16/20 6:20 70,119 96 $1,439,827
Control rod misalignment during testing due to original construction wire lug crimp deficiency failing after
decades of operation, thereby requiring unit shutdown
per operating license. No
2 7/17/20 13:46 8/2/20 12:25 425,889 583 $12,276,673 Generator cooling system high cycle fatigue failure requiring unit shutdown to repair.

Event addressed in 2021 ERRA
compliance proceeding (A.22-02-
025). No decision in this proceeding
has been issued.
2 10/15/20 3:44 11/26/20 13:31 1,132,793 1,552 $49,326,713 Other generator high cycle fatigue failures requiring unit shutdown to repair.

Event addressed in 2021 ERRA
compliance proceeding (A.22-02-
025). No decision in this proceeding
has been issued.
2 12/2/20 13:17 1/12/21 17:44 1,100,145 1,507 $41,932,354 Other generator high cycle fatigue failures requiring unit shutdown to repair.

Event addressed in 2021 ERRA
compliance proceeding (A.22-02-
025). No decision in this proceeding
has been issued.
2 4/19/21 15:09 4/25/21 5:23 149,402 205 $3,754,147
Contractor error in reconnection of generator cooling
hoses requiring unit shutdown to correct.

Event addressed in 2021 ERRA
compliance proceeding (A.22-02-
025). No decision in this proceeding
has been issued.
2 10/15/21 17:49 11/3/21 5:01 493,282 676 $28,070,513
Feedwater heater tube leak from first in industry failure mechanism required unit shutdown to repair.

Event addressed in 2021 ERRA
compliance proceeding (A.22-02-
025). No decision in this proceeding
has been issued.
1 4/23/22 0:03 4/26/22 17:36 100,027 137 $4,009,040
Blowdown system pressure control system failed
resulting in condenser air in-leakage requiring unit
shutdown to repair.

Event addressed in 2022 ERRA
compliance proceeding (A.23-02-
018). No decision in this proceeding
has been issued.
2 5/24/24 2:33 5/25/24 9:55 35,037 48 $442,392 Steam line gasket leak during power ascension after refueling outage 2R24. Cause is under evaluation.

This event will be addressed in the
2024 ERRA compliance proceeding
to be filed in February 2025.

Basis of Lost Generation:

Lost generation provided is the maximum dependable capacity of the unit multiplied by the hours the unit was offline.

Basis of Lost Capacity:

MW-Month is not an industry recognized term for lost capacity; the value provided in the table is the total MW generation lost for a given outage divided by the hours in a normalized month (i.e. Lost generation output / (30.42 days/month x 24 hrs/day)).

Basis of Replacement Power Cost:

Above listed replacement power costs were determined using the Joint Stipulation Regarding Replacement Cost of Energy between the Office of Ratepayer Advocates and Pacific Gas and Electric Company, Dated September 4, 2014. Refer to 2013 ERRA compliance proceeding (A.14-02-008).

Rows 2 and 3 were based on the 2013 ERRA compliance proceeding (A.14-02-008) Decision 18-05-025 dated May 31, 2018, pages 28 and 33 respectively Row 5 was previously provided in response to Office of Rate Payer Advocates Data Request 002 Question 005 in 2014 ERRA Compliance Proceeding (A15-02-023) Row 9 was previously provided in response to Joint CCAs Data Request 002 Question 47 in the 2020 ERRA Compliance Proceeding (A21-03-008) Row 10 -14 were previously provided in response to Alliance for Nuclear Responsibility (A4NR) Data Request 002 Question 003 in the 2021 ERRA Compliance Proceeding (A22-02-015) Row 15 was previously provided in response to Cal CCA Data Request 002 Question 007 in the 2022 ERRA Compliance Proceeding (A23-02-018) Note Row 16 was based on analysis with data available at time of data request (estimate subject to change, e.g., pending possible updates to CAISO final settlement values).

DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002-Q013 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
DCPP Extended Operations 2025 Forecast
Application 24-03-018
Data Response
PG&E Data Request No.: CalCCA_002-Q013
PG&E File Name: DCPP-ExtendedOperations2025-Forecast_DR_CalCCA_002-Q013 Request Date: June 19, 2024 Requester DR No.: 002
Date Sent: July 5, 2024 Requesting Party: California Community Choice Association
PG&E Witness: Thomas R. Baldwin Requester: Corey Cochran QUESTION 013
Referring to PG&E’s prepared testimony page 7-7, line 28, through page 7-8, line 17:

Has the Commission ever determined that an unplanned outage of a DCPP unit was due to failure of the operator to meet the reasonable manager standard. If yes, please explain in detail.

ANSWER 013
PG&E objects to this request on the grounds that CalCCA’s request is outside the scope of the proceeding. Subject to and notwithstanding this objection, PG&E responds as follows:

To respond to this question, PG&E reviewed the Energy Resource Recovery Account (ERRA) compliance proceedings back to 2010. In that review, PG&E has identified one such occurrence, which was with respect to a DCPP Unit 2 outage on October 11, 2012 that occurred due to a flashover on the "A" phase Coupling Capacitor Voltage Transformer. The event was presented in Application 13-02-023 and is discussed in detail in Section 9 of Decision 16-04-006.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Application of Pacific Gas and Electric Company
(U39E) for Review of the Disadvantaged
Communities – Green Tariff, Community Solar
Green Tariff and Green Tariff Shared Renewables
Programs.

A.22-05-022
And Related Matters. A.22-05-023
A.22-05-024

REPLY COMMENTS OF THE JOINT COMMUNITY CHOICE AGGREGATORS AND CITY AND COUNTY OF SAN FRANCISCO ON ADMINISTRATIVE LAW JUDGE’S

RULING DIRECTING RESPONSES TO QUESTIONS REGARDING
IMPLEMENTATION OF DECISION 24-05-065
Brittany Iles
BRAUN BLAISING & WYNNE, P.C.
555 Capitol Mall, Suite 570
Sacramento, CA 95814
Telephone: (916) 326-5812
E-mail: [email protected]
July 29, 2024 Attorney for the
Joint Community Choice Aggregators and
City and County of San Francisco
i

TABLE OF CONTENTS
I. INTRODUCTION .................................................................................................................. 1 II. REPLY .................................................................................................................................... 2 A. CCA PARTICIPATION....................................................................................................... 2 i. Assembly Bill 2316 and the Decision Authorize CCAs and IOUs to Administer CRE Programs on Behalf of Their Customers.......................................................................... 2 ii. Program Funding Should be Allocated to Participating Load Serving Entities Based on Load Share ....................................................................................................................... 4 B. DEVELOPER COMPENSATION ..................................................................................... 6 i. Foundational Tariffs Must be Updated to Include Energy Storage.................................. 6 ii. The Commission Should Facilitate a Working Group to Establish a Methodology for Developer Compensation Beyond the Base Payments Provided by the Foundational Tariffs............................................................................................................................... 7 iii. Upfront Payments to Developers Would Require Established Guardrails to Ensure Proper Use of Funds......................................................................................................... 8 C. CUSTOMER ENROLLMENT AND BILL CREDIT ...................................................... 10 i. Program Administrators Should Enroll All CRE Program Participants ........................ 10 ii. CRE Program Bill Credits Should be Provided to Low-Income Customers Only .........11 iii. The “Revenue Share” for Low-Income Customers Should be Set as a 20% Discount off of the Electric Bill .................................................................................................... 12 III. CONCLUSION................................................................................................................. 13 1 BEFORE THE PUBLIC UTILITIES COMMISSION

A.22-05-022
And Related Matters. A.22-05-023
A.22-05-024

REPLY COMMENTS OF THE JOINT COMMUNITY CHOICE AGGREGATORS AND CITY AND COUNTY OF SAN FRANCISCO ON ADMINISTRATIVE LAW JUDGE’S

RULING DIRECTING RESPONSES TO QUESTIONS REGARDING
IMPLEMENTATION OF DECISION 24-05-065
I. INTRODUCTION
In accordance with the California Public Utilities Commission’s (“CPUC or “Commission”) Administrative Law Judge’s Ruling Directing Responses to Questions Regarding Implementation of Decision 24-05-065 dated June 5, 2024 (“ALJ Ruling” or “Ruling”), Ava Community Energy (“Ava”), Clean Power Alliance of Southern California (“CPA”), the City and County of San Francisco, acting by and through its Public Utilities Commission (“CleanPowerSF”), Lancaster Choice Energy (“LCE”), Marin Clean Energy (“MCE”), Peninsula Clean Energy Authority (“PCE”), Pico Rivera Innovative Municipal Energy (“PRIME”), San Diego Community Power (“SDCP”), San Jacinto Power (“SJP”), and San José Clean Energy (“SJCE”) (collectively, the “Joint Community Choice Aggregators” or “Joint CCAs”) hereby submit these Reply Comments.

The Joint CCAs are encouraged by the robust participation of a variety of stakeholders in the development of the implementation details of the Community Renewable Energy (“CRE”) 2 Program as adopted in Decision (“D.”) 24-05-065 (“the Decision”). At the same time, the variation in the many proposals regarding the structure of the tariffs, developer compensation, and customer incentives may be difficult to reconcile into a single proposal. As a threshold matter, the Joint CCAs would like to highlight that California already has a well-functioning community solar program, the Disadvantaged Communities (“DAC”) Green Tariff (“DAC-GT”) program. The Joint CCAs strongly recommend that the new CRE Program be modeled after the existing DAC-GT program to ensure consistency across community solar programs in California and to achieve significant administrative efficiencies considering the limited program funding.

The following Reply Comments are submitted with this goal in mind and focus on three core topic areas: (1) CCA participation under the CRE Program; (2) developer compensation; and (3) customer enrollment and bill credit.

II. REPLY
A. CCA PARTICIPATION
i. Assembly Bill 2316 and the Decision Authorize CCAs and IOUs to Administer CRE Programs on Behalf of Their Customers
The Commission should disregard comments by Southern California Edison Company (“SCE”) stating that the CRE Program should be administered by the Investor Owned Utilities (“IOUs”) on behalf of all customers including bundled, community choice aggregator (“CCA”) and direct access customers.1 SCE argues that CCAs cannot contract for, and administer, CRE projects under the CRE Foundational Tariffs. SCE further argues that because CCA participation would be voluntary, allowing a CCA’s tariff to serve as a Foundational Tariff for the CRE Program would not ensure all CCA customers can participate.2 1 Opening Comments of Southern California Edison Company on ALJ Ruling (“SCE Opening Comments”) at 10.
2 SCE Opening Comments at 22.
3 Assembly Bill (“AB”) 2316 makes clear that CCAs and electric service providers (“ESPs”) may participate in any new community renewable energy program established by the Commission.3 Additionally, the Decision explicitly states that “CCAs are permitted to participate in the new community renewable energy program” and, as such, “the foundational tariffs will need to be revised to accommodate this participation.”4 The Decision further confirmed that a future ruling on the details of the CRE Program would include questions around the process for CCA participation in the program, as well as which CCA tariffs would be eligible for the program.5 These provisions clearly outline that CCAs are permitted to participate in the CRE Program if they decide to do so. As such, it is not relevant whether CCAs may currently offer the Foundational Tariffs, as the Decision is clear that the Foundational Tariffs must be revised to ensure CCA participation.

In addition to being contrary to statute and the Decision, SCE’s proposal is not in line with the other IOUs’ proposals. San Diego Gas & Electric Company (“SDG&E”), for example, is opposed to serving unbundled customers in SDG&E’s service territory, further stating that SDG&E supports CCAs “being able to offer whatever choices and programs to customers that they would like to; expanding customer choice.”6 SDG&E further states that CCAs should have the authority to market the CRE Program directly to their customers without creating confusion.7 Pacific Gas & Electric Company (“PG&E”) also supports CCAs offering the CRE Program to 3 See Pub. Util. Code Section 769.3(b)(2)(B).
4 D.24-05-065 at 148.
5 Id. at 151.
6 Comments of San Diego Gas & Electric Company Per ALJ Ruling (“SDG&E Opening Comments”) at 4.
7 SDG&E Opening Comments at 3-4.
4 their customers.
8 Many parties agree.9 Pursuant to AB 2316 and the Decision, a CCA must be able to administer the CRE Program on behalf of their own customers if they elect to do so. ii. Program Funding Should be Allocated to Participating Load Serving Entities Based on Load Share
As noted in parties’ Opening Comments, the program capacity for the CRE Program is implicitly limited due to the public funding available for the program. 10 While the Decision
doesn’t establish an explicit program cap for the CRE Program, as noted in Opening Comments, the Joint CCAs calculate that the allocated funding amount will effectively limit the CRE Program to around 50 MW.11 Taking into account the limited funding, and therefore, limited program capacity, the Commission should determine a methodology for allocating either the available funding or capacity to the participating load serving entities (“LSEs”) administering the CRE Program. While many parties in Opening Comments focused on the allocation of funds among customers and developers in response to the ALJ Ruling, it is equally important to consider the allocation of funds among each LSE, or program administer.12 In general, the Joint CCAs support Opening Comments stating that participating LSEs should be allocated a 8 Opening Comments of Pacific Gas and Electric Company in Response to ALJ Ruling (“PG&E Opening Comments”) at 17.
9 See Comments of Dimension Renewable Energy on ALJ Ruling (“Dimension Opening Comments”) at 25 (“CCAs have the ability to develop their own wholesale energy contracts and tariffs for enabling this program”); Comments of the Solar Energy Industries Association on the Implementation of D.24-05-065 (“SEIA Opening Comments”) at 23 (“CCAs should have full authority to manage their own CREP procurement and the disbursement of their share of incentive funds to projects and subscribers”); Clean Coalition Comments on ALJ Ruling (“Clean Coalition Opening Comments”) at 10 (“CCAs should have the flexibility to develop FITs with additional compensation beyond what is provided in ReMAT or the SOC”).
10 SCE Opening Comments at 4 (“Given the current funding that is available, the CRE program should organically start smaller than it may potentially be as more funding materializes…”); see also SEIA Opening Comments at 18-19.
11 Opening Comments of the Joint CCAs on ALJ Ruling (“Joint CCA Opening Comments”) at 6. 12 See ALJ Ruling at 4-5, Question 4.
5 proportional share of non-rate payer funding based on their respective load shares within the state.13
Specifically, the Joint CCAs propose (1) that available program funding for the CRE Program be allocated among the participating LSEs, and (2) that the funding be split between participating LSEs based on load share following the process described below. First, the Joint CCAs believe that as the program funding is the limiting factor for the CRE Program, allocating the funding, rather than capacity, provides a simpler approach than calculating a capacity cap based on the available funding and, in turn, allocating that capacity among the LSEs. Second, the Joint CCAs believe the load share approach is a reasonable and fair methodology for allocating program funding as this method encourages appropriate resource distribution based on the demand each LSE serves.
14 Further, as mentioned above in Section II.A.i., CCAs and ESPs are permitted to participate in the CRE Program if they elect to. It is important to note that this includes all CCAs and ESPs, not just those CCAs currently administering a DAC-GT program. Under the Joint CCAs’ proposal in Opening Comments, and as is consistent with AB 2316, CCAs [and ESPs] would have 180 days upon the issuance of a second decision in this proceeding to submit their own CRE Program tariffs through a Tier 2 Advice Letter, thereby notifying the Commission of the intent to participate in the CRE Program.15 Once all LSEs have indicated their interest in offering the CRE Program, available public funding would then be split among participating LSEs based on each LSEs’ load share.
13 See Dimension Opening Comments at 7; Valta Energy Comments on ALJ Ruling (“Valta Opening Comments”) at 1; SEIA Opening Comments at 23.
14 See Valta Opening Comments at 1.
15 See Pub. Util. Code § 769.3(b)(2)(B); see also Joint CCAs Opening Comments at 22. 6 B. DEVELOPER COMPENSATION
i. Foundational Tariffs Must be Updated to Include Energy Storage Many parties highlight in Opening Comments the importance of incorporating energy storage under the CRE program and provide a variety of proposals of how energy storage should be compensated under the program.
16 The Joint CCAs would like to take this opportunity to further elaborate on their proposal made in Opening Comments regarding the treatment of energy storage under the CRE Program. The Joint CCAs believe that the Decision gives the Commission the authority to update the existing Foundational Tariffs to align them with the rules and requirements of the CRE Program, including the inclusion of solar + storage projects.17 The Joint CCAs propose that there be two “CRE Program Tariffs” created by each LSE offering the CRE Program – one CRE Program tariff offering standard pricing for solar only resources ($/kWh for energy produced) and one CRE Program tariff offering standard pricing for solar + storage resources ($/kWh for energy produced by solar system and $/kW-month for the capacity provided by the storage system). The Commission would set the pricing/developer compensation under both CRE Program Tariffs, i.e. the Commission would also establish the “base payment” for the energy storage resource for co-located solar + storage systems. For solar + storage systems, both the base energy and capacity payments (if the project has deliverability) would be paid by ratepayers as they reflect costs that the LSEs incur if they were to procure solar + storage resources outside of the CRE Program. Only adders to the developer compensation that go above 16 See D.24-05-065 at 169, OP 1(i) (“Storage – The community renewable energy program tariff shall allow for co-located solar and storage.”); see also Valta Opening Comments; Dimension Opening Comments; SEIA Opening Comments; Cypress Creek Opening Comments; Cal Advocates Opening Comments; CCSA Opening Comments.
17 See generally id. at 169, OP 1 (describing the adopted elements of a community renewable energy program).
7 and beyond the usual procurement costs (a concept called “above market generation costs” under the DAC-GT program) would be recovered by CRE Funding.
18 ii. The Commission Should Facilitate a Working Group to Establish a Methodology for Developer Compensation Beyond the Base Payments Provided by the Foundational Tariffs
The majority of parties highlight in Opening Comments that additional “adders” must be provided beyond the base payment provided by the Foundational Tariffs to allow for local, distributed project development under the CRE Program.
19 However, there is currently no
alignment on the methodology that should be used to establish the level of those adders. Opening Comments include a range of proposals for calculating the adders including, for example, proposals based on the Cost of Renewable Energy Spreadsheet Tool (“CREST”) model,20 a reverse auction mechanism,21 a set adder of 5%,22 a comparison to DAC-GT procurement costs,23 or a “missing money” revenue requirement calculation.24 The Joint CCAs support the further exploration of the proposed methodologies and suggest the Commission give parties the opportunity to present their proposals in more detail in working group sessions. Based on the discussions in the working group sessions, the Commission and parties may decide on the most 18 “CRE Funding” refers to the funding set aside in the Decision for the CRE Program including the $33 million appropriated to the Commission by AB 102 for community energy renewable program usage and storage-backed renewable generation programs, as well as the Environmental Protection Agency’s (“EPA”) Solar for All grant funding.
19 See e.g., Opening Comments of the Joint CCAs; Opening Comments of the Coalition for Community Solar Access on ALJ Ruling (“CCSA Opening Comments”); Opening Comments of The Utility Reform Networks on the ALJ Ruling (“TURN Opening Comments”) at 5; Opening Comments of the Public Advocates Office on ALJ Ruling (“Cal Advocates Opening Comments”) at 10; SCE Opening Comments; PG&E Opening Comments.
20 CCSA Opening Comments at 30.
21 TURN Opening Comments at 5; Cal Advocates Opening Comments at 10. 22 SCE Opening Comments at 3.
23 PG&E Opening Comments at 12.
24 SEIA Opening Comments at 8.
8 appropriate valuation methodology to establish the “adders” provided to developers under the CRE Program.
iii. Upfront Payments to Developers Would Require Established Guardrails to Ensure Proper Use of Funds
Several industry representatives propose that a portion of the developer compensation should be paid “upfront,” presumably once a project has reached its Commercial Operation Date (“COD”).
25 The Joint CCAs have concerns about this proposal and recommend that, if such a proposal were to be adopted, specific guardrails must be established to ensure the funds are appropriately used.

Providing upfront payments to developers poses risks to an LSE as payments are made in advance of the delivery of services under the contract. There could be performance issues with the project throughout the duration of the contract term that could prove challenging to address if payments had already been made. Additionally, stakeholders reference incentive programs for behind-the-meter (“BTM”) resources as examples for upfront incentives (such as the California Solar Initiative (“CSI”)).
26 This is not a direct comparison as those solar projects operate on a much smaller scale. With significantly larger project sizes under the CRE Program come increased costs, and therefore, increased potential risk when providing upfront incentives and an increased need to protect against those risks.

The risks and challenges mentioned above, absent proper guardrails, could result in long and cumbersome legal processes to claw back already paid upfront incentives from developers for non-performance under a project, or otherwise risk depletion of CRE Funding without CRE Projects performing as projected. Any claw back provisions or other methodologies in the event 25 See e.g. CCSA Opening Comments at 30; SEIA Opening Comments at 18; Dimension Opening Comments at 9-10; Clean Coalition Opening Comments at 4-5; Valta Opening Comments at 2-3. 26 Dimension Opening Comments at 10.
9 of delay or non-performance under a project should therefore be carefully vetted and determined through parties in this proceeding if the Commission were to consider adoption of this proposal.

For example, any upfront incentives that are clawed back from a developer, such as in the scenario described above, should be returned to the LSE administering the CRE Program.

The Joint CCAs acknowledge the challenge provided by the Solar for All programs’ five-year performance period. However, when looking more closely into the language in the Environmental Protection Agency’s (“EPA”) Request for Applications (“RFA”) for the Solar for All Program (EPA-R-HQ-SFA-23-01), EPA notes that “[a]ll activities funded with the initial grant award must be completed within the negotiated program performance period of up to five years, meaning all program grant funds must be deployed [emphasis added] as described in the application.”27 The Joint CCAs note that there could be a variety of definitions for the “deployment” of grant funds. For example, one could argue that grant funds are “deployed” if they are set aside for a particular solar (or solar + storage resource) for its entire performance term (e.g. 20 years). More specifically, an LSE could forecast the payments to the developer paid by Solar for All funding upon COD of the resource as established in the power purchase agreement terms and/or the CRE Program tariffs. This funding could then essentially be “set aside” for the project in the utilities’ balancing accounts and would be paid out to the developer per the standard contract terms. Such a process could possibly fulfill the requirement of the EPA to “deploy” the grant funds within 5 years. The Joint CCAs are hopeful that the California Energy Commission (“CEC“) (the implementing agency of Solar for All funding in California) can work with the EPA to find a workable solution for community solar in California. 27 See EPA Solar for All RFA at 26, available at https://www.grants.gov/search-results-detail/348957 10 C. CUSTOMER ENROLLMENT AND BILL CREDIT
i. Program Administrators Should Enroll All CRE Program Participants
CRE Program enrollment of eligible customers should only be the responsibility of the LSEs administering the program. In Opening Comments, Dimension proposes that projects would be responsible for subscribing up to 25% of the subscribers in that project while the LSE would be responsible for the other 75%.28 Dimension provides that “a division of labor for customer acquisition and management between the solar + storage project and the utility best balances the goals of [Solar for All], the non-energy benefits of community solar (such as community engagement and workforce development), and the limited funding available to support customer savings.”29 However, this approach would likely create confusion and unnecessary administrative burdens. It is simpler and more cost-effective for LSEs to be responsible for all customer enrollment under the CRE Program as proposed by the Joint CCAs, as well as other parties, in Opening Comments.
30 Additionally, TURN proposes a statewide third-party administrator to manage enrollment and provide customer-facing information about the CRE Program. TURN argues that this “would provide a uniform engagement and education experience for customers of different [LSEs]” and that there “are likely efficiencies with using a single entity for this task rather than spreading it across multiple utilities and CCAs.”31 The Joint CCAs fundamentally disagree with the recommendation to impose a third-party administrator to manage any CRE Program enrollment or promotion of the program. As the Joint CCAs have noted multiple times throughout this 28 Dimension Opening Comments at 5-6.
29 Id. at 5.
30 See Joint CCAs Opening Comments; see also SCE Opening Comments at 26-27. 31 TURN Opening Comments at 16.
11 proceeding, a centralized marketing entity would not be able to effectively serve the local communities like CCA program administrators can.32 In fact, providing a “uniform” engagement and education experience, as suggested by TURN, would severely limit a main benefit of CCA participation in the CRE Program, namely, the ability of CCAs to adapt the CRE Program to the needs of their local communities.
ii. CRE Program Bill Credits Should be Provided to Low-Income Customers Only
Multiple parties advocate for bill credits being provided to only low-income customers for various reasons, including limited funding.33 However, PG&E proposes to provide bill credits to low-income customers, as well as Title 24 customers. PG&E suggests that this is appropriate given “the statutory focus of AB 2316 on both low-income customers and consistency with Title

24.”34 While the Joint CCAs agree that there should be a focus under the CRE Program on the enrollment of customers looking to fulfill Title 24 compliance, the Joint CCAs do not believe that it is appropriate to give bill credits to Title 24 customers. The Joint CCAs do not believe that consistency with Title 24, as required by AB 2316, requires a bill credit for Title 24 customers.35 However, under the Joint CCAs’ proposal as outlined in Opening Comments,36 non-low-income customers participating in the CRE Program and seeking Title 24 compliance could achieve Title 24 compliance at no additional cost. This, in and of itself, is a substantial benefit and incentive in 32 See e.g. Exhibit JCCA-02: Prepared Rebuttal Testimony on Behalf of the Joint Community Choice Aggregators and City and County of San Francisco (“Joint CCA Rebuttal Testimony”) 33 See CCSA Opening Comments at 35 (“CCSA does not recommend the Commission establish a minimum bill savings for non-low-income subscribers”); SCE Opening Comments at 4 (proposing that the CRE program should use the external funding to provide bill credits only to low-income subscribers). 34 PG&E Opening Comments at 2.
35 See Pub. Util. Code Section 769.3(c)(1) (stating that a new community renewable energy program must be complementary to, and consistent with the requirements of Title 24 with consultation of the California Energy Commission).
36 Joint CCAs Opening Comments at 17.
12 pursuing and achieving Title 24 compliance. Furthermore, the Joint CCAs support providing the maximum amount of bill support possible for low-income customers given the limited funding under the CRE Program.
37 Finally, the CRE Funding currently available for the program is limited to funding bill credits for low-income customers and those located in disadvantaged communities only; namely the Solar for All funding is limited to low-income and disadvantaged communities38 and the $33 million appropriated to the Commission are intended to “support disadvantaged community renewable generation and storage-backed renewable generation programs.” 39 For all of these
reasons, the Joint CCA recommend that bill credits should only be provided to low-income customers under the CRE Program.
iii. The “Revenue Share” for Low-Income Customers Should be Set as a 20% Discount off of the Electric Bill
In Opening Comments, the Joint CCAs supported SCE’s proposal to provide low-income subscribers with an incentive based on 20% of the power purchase agreement price provided under the specific CRE project that the customer subscribes to in an effort to approximate the interest of the Commission to enable a “project revenue share” for subscribing customers. 40 However, upon further review of the Solar for All funding requirements, the Joint CCAs believe that low-income customers must be offered a minimum 20% discount off of their bill for the CRE program to be eligible for Solar for All funding ("Delivering a minimum of 20% household savings....; household savings is defined as 20% of the average household electricity bill in the 37 See Joint CCA Opening Comments at 8-9 (describing the funding limitations of the CRE Program).
38 See EPA Solar for All RFA at 26, available at https://www.grants.gov/search-results-detail/348957. 39 AB 102, Budget Act of 2023, Section 244.
40 See Joint CCA Opening Comments at 15.
13 utility territory”).41 The CEC, as the implementing agency of the Solar for All funding in California, should discuss with EPA if this could be interpreted as a 20% bill discount of a specific customers’ otherwise applicable tariff (instead of the average) as is customary under the DAC-GT program. If this were to be feasible, the implementation of the bill discount under the CRE Program would be significantly streamlined and implementation costs would be significantly reduced, as it would simply follow the existing bill discount methodology under the DAC-GT programs. It would also provide more equality between low-income customers participating in the various community solar programs in California.

III. CONCLUSION
The Joint CCAs thank the Commission for its consideration of the matters set forth in these comments.

July 29, 2024 Respectfully Submitted,
/s/ Brittany Iles
Brittany Iles
BRAUN BLAISING & WYNNE, P.C.
555 Capitol Mall, Suite 570
Sacramento, California 95814
Telephone: (916) 326-5812
E-mail: [email protected]
Attorney for the
Joint Community Choice Aggregators and
City and County of San Francisco
41 See EPA Solar for All RFA at 12, available at https://www.grants.gov/search-results-detail/348957.

July 29, 2024
VIA ELECTRONIC MAIL: ([email protected])
Public Utilities Commission of the State of California
Energy Division
Attention: Tariff Unit
505 Van Ness Avenue, 4th Floor
San Francisco, CA 94102
Advice Letter 15-E
Apple Valley Choice Energy
Advice Letter 48-E
Ava Community Energy
Advice Letter 41-E
Central Coast Community
Energy
Advice Letter 9-E
Clean Energy Alliance
Advice Letter 27-E
Clean Power Alliance
Advice Letter 29-E
CleanPowerSF
Advice Letter 10-E
Desert Community Energy
Advice Letter 6-E
Energy For Palmdale’s
Independent Choice
Advice Letter 28-E
Lancaster Energy
Advice Letter 78-E
Marin Clean Energy
Advice Letter 9-E
Orange County Power
Authority
Advice Letter 34-E
Peninsula Clean Energy
Advice Letter 23-E
Pico Rivera Innovative
Municipal Energy
Advice Letter 19-E
Pioneer Community Energy
Advice Letter 10-E
Pomona Choice Energy
Advice Letter 13-E
Rancho Mirage Energy
Authority
Advice Letter 21-E
Redwood Coast Energy
Authority
Advice Letter 20-E
San Diego Community
Power
Advice Letter 21-E
San Jacinto Power
Advice Letter 35-E
San José Clean Energy
Advice Letter 6-E
Santa Barbara Clean
Energy
Advice Letter 32-E
Silicon Valley Clean Energy
Advice Letter 23-E
Sonoma Clean Power
Advice Letter 18-E
Valley Clean Energy
RE: CALCCA’S REPLY TO JOINT UTILITIES’ PROTEST TO APPLE VALLEY CHOICE ENERGY ADVICE LETTER 15-E, ET AL. (CONSOLIDATED)

SUBMITTED BY CALCCA ON BEHALF OF THE JOINT CCAS TO AID IN

THE IMPLEMENTATION OF COMMUNITY CHOICE AGGREGATOR

FINANCIAL MONITORING AND REPORTING REQUIREMENTS ADOPTED IN DECISION 24-04-009
California Community Choice Association (CalCCA) submits this Reply to the protest of San Diego Gas & Electric Company (SDG&E), Southern California Edison Company (SCE), and Pacific Gas and Electric Company (PG&E) (together, the Joint Utilities), dated July 22, 2024, to the Tier 2 Advice Letter (Advice Letter) submitted by CalCCA, on behalf of Apple CalCCA Reply to Joint Utilities’ Protest

Page 2 ends

July 29, 2024
Valley Choice Energy, Ava Community Energy, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance, 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 Energy1 (collectively, the Joint CCAs). This Advice Letter seeks to aid Energy Division staff in the implementation of Ordering Paragraph 7 of Decision (D.) 24-04-0092 as well as provide clarity to the Joint CCAs on required reporting triggers.

The Joint Utilities’ protest asks the California Public Utilities Commission (Commission) to reject the Joint CCAs’ Advice Letter entirely, stating, “(i) it is procedurally improper because the Joint CCAs have not been authorized to seek the relief requested through the advice letter process; (ii) the relief requested in the Consolidated AL cannot be granted since the Proposed Guidelines violate the POLR Decision; and (iii) the Consolidated AL is an improper collateral attack on the POLR Decision.”3
In this Reply, and the revised Financial Monitoring Guidance Document, the Joint CCAs correct two unintended errors in the original Financial Monitoring Guidance Document regarding the calculation of cash reserves and confidentiality. It also explains why the Commission should not adopt the Joint Utilities’ recommendation to reject the Joint CCAs’ Advice Letter in full, given (1) the Decision’s intent is not explicit in some areas, and (2) the clarity and consistency in how CCAs monitor Tier 2 triggers through the Financial Monitoring Guidance Document does not violate the POLR Decision or its intent.

I. THE JOINT CCAS ADOPT MODIFICATIONS TO THE FINANCIAL

MONITORING GUIDANCE DOCUMENT TO CORRECT UNINTENTIONAL
ERRORS
The intent of the Joint CCAs’ Financial Monitoring Guidance Document is to provide clarity where the Decision left room for interpretation, not to make changes to the Decision.

Adoption of the revised Financial Monitoring Guidance Document would not change the fact that the Joint CCAs are obligated to fully comply with the Decision as adopted.

The Joint Utilities’ protest identified inadvertent errors in the Financial Monitoring Guidance Document that the Joint CCAs agree require modification to ensure consistency with the Decision language. These modifications are documented in the clean and redlined version 1 The Joint CCAs have provided CalCCA with authority to submit this Advice Letter on their behalf. 2 D.24-04-009, Decision Implementing Senate Bill 520 Regarding Standards for Provider of Last Resort, R.21-03-011 (Apr. 18, 2024) (the Decision or, the POLR Decision):
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M529/K986/529986322.PDF. 3 Joint Utilities’ protest at 3, footnotes omitted.

CalCCA Reply to Joint Utilities’ Protest

Page 3 ends

July 29, 2024
(Attachment A and Attachment B, respectively) of the revised Financial Monitoring Guidance Document attached to this Reply, and described here:
• Modifies the Cash Reserves explanation from “It should not consider a city’s general fund cash reserves” to “It shall not consider a city’s general fund cash reserves.” • Removes all references to confidentiality in all places except section 4. The use of “confidential” in other sections reflects outdated language and has been removed. • Modified Section 4 to ensure it directly reflects the Decision language.

The Commission should adopt the revised Financial Monitoring Guidance Document attached to this Reply. The revisions are intended to make it consistent with the already clear Decision language. The rest of the document informs elements of the Decision that are ambiguous.

II. THE COMMISSION SHOULD REJECT THE JOINT UTILITIES’

PROCEDURAL ARGUMENTS THAT THE JOINT CCAS ARE NOT

AUTHORIZED MAKE ITS RECOMMENDATIONS IN THE ADVICE LETTER The Joint Utilities make several procedural arguments in attempts to support their recommendation to reject the Joint CCAs’ Advice Letter in full. First, the Joint Utilities state, “[t]he POLR Decision did not direct or authorize the CCAs to submit an advice letter to implement the financial reporting rules established in the decision, nor is such an action necessary.”4 CalCCA contacted Energy Division staff to discuss the lack of clarity that the final decision contained. CCAs would need clarity on these items to ensure that they are able to take correct action given that the Decision contains significant new requirements as well as the potential for financial penalties for failing to report as required. The Advice Letter was filed to provide such clarity after consultation with Energy Division staff. CalCCA worked with Energy Division staff on how they could implement these clarifications and through consultation, it was clear that an advice letter was the preferred venue for these clarifications.

Second, the Joint Utilities suggest that “…the advice letter process is not the proper vehicle for challenging the POLR Decision” and that the Joint CCAs’ Advice Letter represents a “collateral attack” on the Provider of Last Resort (POLR) Decision. 5 The Joint CCAs’ Advice
Letter does not challenge the POLR Decision. The volume and intricate detail of new requirements will benefit from clarification so that CCAs can effectively comply with the order.

If the Energy Division staff believes these clarifications would change the final POLR Decision, it will inform the Joint CCAs through this process.

III. THE COMMISSION SHOULD ADOPT THE REVISED FINANCIAL

MONITORING GUIDANCE DOCUMENT TO MAKE CLEAR AREAS OF THE

DECISION THAT WERE NOT EXPLICIT
4 Joint Utilities’ protest at 8.
5 Id. at 8-9.

CalCCA Reply to Joint Utilities’ Protest

Page 4 ends

July 29, 2024
The Joint Utilities took issue with two specific clarifications that CalCCA requested in its Advice Letter. First, the Joint Utilities objected to clarifying that a letter of credit was not the only credit instrument acceptable in calculating Days Liquidity on Hand (DLOH).6 Second, the Joint Utilities find it unacceptable to allow a CCA reasonable opportunity to perform typical monthly financial reviews, accept the financial statement, and then report if necessary.7

The Joint Utilities interpret the Decision as strictly defining DLOH. However, the concept of DLOH is used worldwide for many reasons. It is designed to demonstrate how long an entity can continue paying its obligations given its access to cash, investments, and financial instruments at its disposal. In doing so, limiting the financial instruments to one specific instrument, such as a letter of credit (LOC), is unnecessarily limiting and was not the intent of the Commission. In fact, the Commission has recognized that CCAs have access to other instruments, allowing a LOC and a surety bond to satisfy a financial security requirement. 8 Further, the Joint Utilities’ claim that a credit agreement “does not represent a flexible or readily available source of liquidity that can be used for general operational needs”9 is false. Credit agreements are flexible and can be used as a source of liquidity for operational and working capital needs. Credit agreements and other lines of credit are simply other instruments that can provide liquidity.

In recognizing that there is more than one instrument, the use of a LOC in the Decision should not be construed as limiting the financial instruments that may be used as that should not have been the intent of the Decision. CalCCA added “credit agreements” to clearly reflect how the calculation would be performed in order to comply with the intent of the calculation for this purpose as well as the standard used worldwide.

The Joint Utilities also claim that the Financial Monitoring Guidance Document would extend the compliance period beyond what is contemplated in the POLR Decision with respect to noticing the Energy Division regarding Tier 2 triggers that require calculations using financial data.
10 This claim is false. Four of the Tier 2 triggers – a drop in credit rating below investment grade, defaulting on a resource adequacy procurement contract, defaulting to the California Independent System Operator Corporation’s scheduling coordinator, or filing for bankruptcy – are discrete events that are easily identifiable. However, the DLOH, Debt Service Coverage ratio, and cash reserves assessments require calculations that rely on financial data that do not become available until the end of a given reporting period and are then reviewed as part of unaudited financial statements for the reporting period. CalCCA discussed this topic with Energy Division staff and concluded that the Commission did not intend to create a monitoring burden that is not feasible or practical. In fact, the Joint Utilities’ example where they selected the trigger event occurring on July 5th is impractical given the calculation of the condition could only 6 Joint Utilities’ protest at 4.
7 Id. at 6-7.
8 The Decision at Conclusions of Law 30. 9
Joint Utilities’ protest at 4.
10 The Tier 2 triggers that require calculations using financial data include: (i) DLOH is less than 45 days and Adjusted Debt Service Coverage Ratio is less than 1.0; and (ii) cash reserves for the CCA fall below 5% of annual expenses.

CalCCA Reply to Joint Utilities’ Protest

Page 5 ends

July 29, 2024
occur after the financial data becomes available at the end of a given reporting period, like the end of the month.

The Joint Utilities’ example also shows why “days” should mean “business days.” The example the Joint Utilities provide would be the day after a holiday and demonstrates why “days” not meaning “business days” is unreasonable. Taken to an extreme, had the trigger happened the day before Thanksgiving Day, the next four days would be consumed by a holiday and weekend. This would then leave only six days (with the last being the following weekend) for the CCA to validate that the trigger had been hit and to file the necessary letter. Also, the Joint Utilities’ description of when Energy Division would request a meeting11 does not make sense, as it would follow that Energy Division would request the meeting after the letter is sent notifying a Tier 2 condition had been met.

The clarification that CalCCA therefore sought is that the definition of “days” meant “business days” as is more applicable to business-related activities. In addition, CalCCA sought clarification that the Commission did not intend for infeasible monitoring and that related monitoring calculations could be reasonably performed along with regular accounting processes based on month-end data during normal unaudited financial statement preparation and reviewed to ensure the accuracy of any needed reporting.

IV. CONCLUSION
For the reasons outlined herein, CalCCA recommends the Commission reject the Joint Utilities’ protest and adopt the revised Financial Monitoring Guidance Document attached to this Reply.

Respectfully,

CALIFORNIA COMMUNITY CHOICE ASSOCIATION
Evelyn Kahl
General Counsel and Director of Policy
cc via email:

Service List: R.21-03-011
11 Joint Utilities’ protest at 7. t

ATTACHMENT A
TO
CALCCA REPLY TO JOINT UTILITIES’ PROTEST TO APPLE VALLEY CHOICE ENERGY ADVICE LETTER 15-E, ET AL. (CONSOLIDATED) SUBMITTED BY

CALCCA ON BEHALF OF THE JOINT CCAS TO AID IN THE IMPLEMENTATION

OF COMMUNITY CHOICE AGGREGATOR FINANCIAL MONITORING AND REPORTING REQUIREMENTS ADOPTED IN DECISION 24-04-009

REVISED FINANCIAL MONITORING GUIDANCE DOCUMENT
REVISED JULY 29, 2024
CLEAN
1 COMMUNITY CHOICE AGGREGATORS (CCA)

FINANCIAL MONITORING AND REPORTING GUIDELINES
UPDATED JULY 29, 2024
Decision (D.) 24-04-009 adopted two tiers of financial monitoring and reporting requirements for CCAs. Under the first tier, all CCAs, regardless of their financial standing or years of operation, are required to provide the Energy Division with a copy of their most recent audited financial information. The audited financial statement shall be provided once a year, in January or July, whichever comes earlier relative to the availability of the audited financial statement. Under the second tier, CCAs must report additional financial information if they meet certain conditions indicative of financial strain. This guideline document supplements D.24-04-009 with additional guidance on (1) how and when to evaluate the conditions for tier-two financial reporting, and (2) reported financial information for tier-two reporting.

1. Conditions that Trigger Tier-Two Financial Reporting Tier 2 reporting applies to CCAs that meet any of the following conditions in Table 1:

Table 1: Tier-Two Reporting Conditions
Condition Explanation
The CCA receives a credit rating below BBB-
/Baa3 from S&P & Moody’s
This condition applies only to CCAs who are
downgraded from an investment grade rating
to a noninvestment grade rating. This
condition does not require all CCAs to obtain
a credit rating.

Days Liquidity on Hand (DLOH) is less than
45 days
Note: this condition triggers Tier 2 reporting only if the Adjusted DSCR trigger is also met.

DLOH is defined as a CCA’s available
unrestricted cash and investments and eligible
unused bank letters of credit, credit
agreements, and capacity under commercial
paper programs, multiplied by 365. This
amount shall then be divided by the total of
the last twelve months of the CCA’s operating
and maintenance expenses, excluding
depreciation and amortization.

Adjusted Debt Service Coverage Ratio
(DSCR) is less than 1.0
Note: this condition triggers Tier 2 reporting only if the DLOH trigger is also met.

Adjusted DSCR is defined as: Numerator: For
the last twelve months, recurring revenue plus
interest income plus withdrawals from a Rate
Stabilization Fund, minus recurring cash
operating expenses and General Fund
Transfers over the prior twelve-month period
(where recurring revenue and recurring
expenses exclude special, one-time items, and
annual operating expenses exclude
depreciation and amortization expenses).
2 Denominator: Aggregate debt service over the
prior twelve-month period (i.e., principal,
interest, and fees, as applicable, associated
with the debt).

Cash reserves for the CCA fall below 5
percent of annual expenses
Cash reserves are defined as cash, cash
equivalents, short-term investments, and
unused credit facilities.

The measure of cash reserves must be directly
tied to the CCA. It shall not consider a city’s
general fund cash reserves.

Where “annual expenses” are defined as the
last twelve months of the CCA’s operating
and maintenance expenses, excluding
depreciation and amortization.

The CCA defaults on one or more
procurement contracts required to meet RA
requirements due to non-payment
This condition is specific to the occurrence of
an event of default for buyer non-payment
after opportunities for disputes and cures have
been exhausted as provided within the
contract.

The CCA defaults to its CAISO scheduling
coordinator due to non-payment
N/A
The CCA becomes insolvent or files for
bankruptcy, or the CCA has a reasonable
expectation that either event will occur
N/A

2. Tier-Two Reporting Requirements
The following conditions must be reported via a letter to the Director of Energy Division within 10 business days of the occurrence:
• The CCA receives a credit rating below BBB-/Baa3 from S&P & Moody’s; • The CCA defaults on one or more procurement contracts required to meet RA requirements due to non-payment;
• The CCA defaults to its CAISO scheduling coordinator due to non-payment; and • The CCA becomes insolvent or files for bankruptcy, or the CCA has a reasonable expectation that either event will occur.

The following conditions must be reported via a letter to the Director of Energy Division within 10 business days of the CCA’s acceptance of a financial statement:
1 • DLOH is less than 45 days and DSCR is less than 1.0; and 1 CCAs regularly review and update financial statements. Unaudited financial statements should be prepared as soon as practicable and, in any event, within sixty days after the end of each month in which the trigger occurred. If updated financial information is obtained after such submittal, the CCA will provide that update to the Director of the Energy Division to help inform any prior trigger reporting. 3 • Cash reserves for the CCA fall below 5 percent of annual expenses.

Upon meeting any of the Tier 2 reporting conditions above and submitting the letter to Energy Division, the CCA must meet with Energy Division as requested, up to one meeting per month, and provide the following information:
• Energy and hedging contracts for the next six months with term details; • Status of all procurement contracts, in particular, those at risk of default; • Detailed financial information as requested by the Commission including, but not limited to, the CCA’s most recent financial statements and DLOH; • Plan for financial correction and/or market exit.

3. Graduating from Tier-Two Reporting Requirements
A CCA will graduate from the Tier 2 reporting requirements if it does not meet any Tier 2 triggers (except for the insolvency/bankruptcy condition) for six consecutive months.

4. Confidentiality
If a CCA believes that its letter notifying the Energy Division of a triggered Tier 2 condition, or any of its attendant reporting, is market sensitive, the CCA must follow the regular Commission process for securing confidential treatment.

5. Enforcement
A CCA that fails to submit a letter to the Energy Division by the deadlines outlined in Section 2 will incur a penalty of $1,000 per incident plus $500 per day for the first ten days the filing was late and $1,000 for each day thereafter. Commission Staff and the Commission may take any action provided by law to recover unpaid penalties and ensure compliance with applicable statutes and Commission orders, decisions, rules, directions, demands, or requirements.

ATTACHMENT B
TO
CALCCA REPLY TO JOINT UTILITIES’ PROTEST TO APPLE VALLEY CHOICE ENERGY ADVICE LETTER 15-E, ET AL. (CONSOLIDATED) SUBMITTED BY

CALCCA ON BEHALF OF THE JOINT CCAS TO AID IN THE IMPLEMENTATION

OF COMMUNITY CHOICE AGGREGATOR FINANCIAL MONITORING AND REPORTING REQUIREMENTSADOPTED IN DECISION 24-04-009

REVISED FINANCIAL MONITORING GUIDANCE DOCUMENT
REVISED JULY 29, 2024

REDLINED
1 COMMUNITY CHOICE AGGREGATORS (CCA)

FINANCIAL MONITORING AND REPORTING GUIDELINES
UPDATED JULY 291, 2024
Decision (D.) 24-04-009 adopted two tiers of financial monitoring and reporting requirements for CCAs. Under the first tier, all CCAs, regardless of their financial standing or years of operation, are required to provide the Energy Division with a copy of their most recent audited financial information. The audited financial statement shall be provided once a year, in January or July, whichever comes earlier relative to the availability of the audited financial statement. Under the second tier, CCAs must report additional financial information if they meet certain conditions indicative of financial strain. This guideline document supplements D.24-04-009 with additional guidance on (1) how and when to evaluate the conditions for tier-two financial reporting, and (2) reported financial information for tier-two reporting.

1. Conditions that Trigger Tier-Two Financial Reporting Tier 2 reporting applies to CCAs that meet any of the following conditions in Table 1:

Days Liquidity on Hand (DLOH) is less than
45 days
Note: this condition triggers Tier 2 reporting only if the Adjusted DSCR trigger is also met.

Adjusted Debt Service Coverage Ratio
(DSCR) is less than 1.0
Note: this condition triggers Tier 2 reporting only if the DLOH trigger is also met.

Cash reserves for the CCA fall below 5
percent of annual expenses
Cash reserves are defined as cash, cash
equivalents, short-term investments, and
unused credit facilities.

The measure of cash reserves must be directly
tied to the CCA. It shouldshall not consider a
city’s general fund cash reserves.

Where “annual expenses” are defined as the
last twelve months of the CCA’s operating
and maintenance expenses, excluding
depreciation and amortization.

The CCA defaults to its CAISO scheduling
coordinator due to non-payment
N/A
The CCA becomes insolvent or files for
bankruptcy, or the CCA has a reasonable
expectation that either event will occur
N/A

2. Tier-Two Reporting Requirements
The following conditions must be reported via a confidential letter to the Director of Energy Division within 10 business days of the occurrence:
 The CCA receives a credit rating below BBB-/Baa3 from S&P & Moody’s;  The CCA defaults on one or more procurement contracts required to meet RA requirements due to non-payment;
 The CCA defaults to its CAISO scheduling coordinator due to non-payment; and  The CCA becomes insolvent or files for bankruptcy, or the CCA has a reasonable expectation that either event will occur.

The following conditions must be reported via a confidential letter to the Director of Energy Division within 10 business days of the CCA’s acceptance of a financial statement:1  DLOH is less than 45 days and DSCR is less than 1.0; and 1 CCAs regularly review and update financial statements. Unaudited financial statements should be prepared as soon as practicable and, in any event, within sixty days after the end of each month in which the trigger occurred. If updated financial information is obtained after such submittal, the CCA will provide that update to the Director of the Energy Division to help inform any prior trigger reporting. 3  Cash reserves for the CCA fall below 5 percent of annual expenses.

Upon meeting any of the Tier 2 reporting conditions above and submitting the confidential letter to Energy Division, the CCA must meet with Energy Division as requested, up to one meeting per month, and provide the following information:
 Energy and hedging contracts for the next six months with term details;  Status of all procurement contracts, in particular, those at risk of default;  Detailed financial information as requested by the Commission including, but not limited to, the CCA’s most recent financial statements and DLOH;  Plan for financial correction and/or market exit.

4. Confidentiality
If a CCA believes that its letter notifying the Energy Division of a triggered Tier 2 condition, or any of its attendant reporting, is market sensitive, the CCA shouldmust follow the regular Commission process for securing confidential treatment.

AUGUST FILINGS

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue
Electric Integrated Resource Planning and
Related Procurement Processes.

R.20-05-003
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S COMMENTS

ON THE PROPOSED DECISION DETERMINING NEED FOR

CENTRALIZED PROCUREMENT OF LONG LEAD-TIME RESOURCES
Evelyn Kahl,
General Counsel and Director of Policy
Lauren Carr,
Senior Market Policy Analyst
Eric Little,
Director of Regulatory Affairs

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
1121 L Street, Suite 400
Sacramento, CA 95814
Telephone: (510) 980-9459
E-mail: [email protected]
August 8, 2024
FILED
08/08/24
12:40 PM
R2005003
i

TABLE OF CONTENTS
I. INTRODUCTION ...............................................................................................................1 II. THE PROPOSED DECISION ERRS BY OMITTING NECESSARY
DETAILS REGARDING THE RELATIONSHIP BETWEEN THE CPE’S
PROCUREMENT AND THE LSE’S PLANNING AND PROCUREMENT
ACTIVITIES........................................................................................................................3 A. The Proposed Decision Must Recognize the Inherent Interactions Between Central Procurement and RCPPP that Cannot be Untangled....................4 B. The Proposed Decision Errs by Neglecting to Include LSE Self-Procurement as a Step in the Process .......................................................................5 C. The Proposed Decision Errs by Not Making all Efforts to Support Customer Affordability through the Ability to Transact Attributes of CPE-Allocated Resources ........................................................................................7 III. THE PROPOSED DECISION ERRS BY BASING ITS PROCUREMENT

CAP ON ANALYSIS THAT DOES NOT DEMONSTRATE A CLEAR
NEED FOR THE TECHNOLOGIES AND AMOUNTS ORDERED ................................8 A. The Proposed Decision Errs in Its Definition of Eligible Resources .......................9 B. The Proposed Decision Bases Its Procurement Caps on Unsupported Conclusions ............................................................................................................11 C. If the Commission Foregoes CalCCA’s Recommendation to Revisit the Need for Central Procurement in Future IRP Cycles, it Must Modify the Proposed Decision to Lower Procurement Cap ..................................13 IV. THE PROPOSED DECISION FAILS TO RECOMMEND THE CPE

RETAIN AN EXPERT CONSULTANT TO MAXIMIZE STATE AND
FEDERAL FUNDING OPPORTUNITIES .......................................................................15 V. CONCLUSION ..................................................................................................................15

APPENDIX
ii

TABLE OF AUTHORITIES
Legislation
AB 1373 ................................................................................................................................. passim SB 100 .................................................................................................................................... passim California Public Utilities Commission Rules of Practice and Procedure Rule 14.3 ......................................................................................................................................... 1 California Public Utilities Commission Proceedings
R.20-05-003 ................................................................................................................................ 1, 9

iii

SUMMARY OF COMMENTS
• The proposed Decision Determining Need for Centralized Procurement of Long Lead-Time Resources (Proposed Decision) errs by omitting necessary details regarding the relationship between the central procurement entity’s (CPE) procurement and the load-serving entities’ (LSE) planning and procurement activities:
o The Proposed Decision must recognize the inherent interactions between central procurement and the Reliable and Clean Power Procurement Program that cannot be untangled;
o The Proposed Decision errs by neglecting to include LSE self-procurement as a step in the process; and
o The Proposed Decision errs by not making all efforts to support customer affordability through the ability to transact attributes of CPE-allocated resources. • The Proposed Decision errs by basing its procurement cap on analysis that does not demonstrate a clear need for the technologies and amounts ordered:
o The Proposed Decision errs in its definition of eligible resources; o The Proposed Decision bases its procurement caps on unsupported analysis; and o If the California Public Utilities Commission foregoes CalCCA’s recommendation to revisit the need for central procurement in future Integrated Resource Planning cycles, it must modify the Proposed Decision to lower the procurement cap. • The Proposed Decision fails to recommend the CPE retain an expert consultant to maximize state and federal funding opportunities.

CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S COMMENTS

ON THE PROPOSED DECISION DETERMINING NEED FOR

CENTRALIZED PROCUREMENT OF LONG LEAD-TIME RESOURCES
The California Community Choice Association (CalCCA)1 submits these comments pursuant to Rule 14.3 of the California Public Utilities Commission (Commission) Rules of Practice and Procedure2 on the proposed Decision Determining Need for Centralized Procurement of Long Lead-Time Resources3 (Proposed Decision or PD), dated July 19, 2024.

I. INTRODUCTION
CalCCA appreciates the Administrative Law Judge’s (ALJ) and Commission staff’s significant efforts to make an initial need determination and develop the process for central procurement under the provisions of Assembly Bill 1373 (Stats. 2023, Ch.367) (AB 1373).

However, the PD misses the mark on several points with respect to these processes’ interactions with load-serving entities’ (LSEs) own planning and procurement activities as part of their right to self-procure for identified needs. The PD’s statement that “…it is logical to keep any CPE procurement as a result of this order separate and apart from any individual LSE requirements driven by the [Reliable and Clean Power Procurement Program (RCPPP)], once adopted,”4 and finding that “CPE
procurement should be kept in a separate category for purposes of consideration of an RCPPP in the 1 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. 2 State of California Public Utilities Commission, Rules of Practice and Procedure, California Code of Regulations Title 20, Division 1, Chapter 1 (May 2021). 3 Proposed Decision Determining Need for Centralized Procurement of Long Lead-Time Resources, Rulemaking (R.) 20-05-003 (July 19, 2024). 4
Id. at 50.
2 future in this proceeding,”5 are false. Central procurement will interact with or, at minimum, significantly impact LSEs’ own procurement and planning processes. Therefore, it is necessary to modify the PD to more completely document central procurement entity (CPE) processes, its interactions with LSE procurement, and LSEs’ abilities to optimize their procurement plans through self-procurement and transacting CPE allocations.

The PD also fails to make its need determination based on a well-supported analysis of the need for the technologies and amounts ordered in the PD. While CalCCA supports the PD’s finding that there is not a need for central procurement of out-of-state wind, the other technologies in the PD and their amounts are not justified. Ordering central procurement that does not have a demonstrated potential for net benefits is a risky and potentially unaffordable endeavor that could hinder LSE procurement and increase customer costs. Because its analysis does not demonstrate a clear need, the Commission should not direct Department of Water Resources (DWR) to centrally procure in this cycle and should instead revisit central procurement in future Integrated Resource Plan (IRP) cycles.

If the Commission forgoes this recommendation and makes a need determination for the initial September 1, 2024, statutory requirement, the Commission should modify its procurement cap to better target the infrastructure development necessary to “help bring emerging technologies to scale”6
and better reflect the most up-to-date LSE procurement and planning information.

The PD also fails to develop a central procurement process and recommendations to the CPE that make “all possible efforts… to contain costs, reduce ratepayer risk, and seek other sources of funding to reduce development costs and share in the long-term costs and benefits.”7 The Commission must revise the PD to address these errors, which include in summary:
5 Proposed Decision, Conclusion of Law (COL) 22.
6 Id. at 3.
7 Id.
3 • The PD errs by omitting necessary details regarding the relationship between the CPE’s procurement and the LSE’s planning and procurement activities:
o The PD must recognize the inherent interactions between central procurement and the RCPPP that cannot be untangled;
o The PD errs by neglecting to include LSE self-procurement as a step in the process; and
o The PD errs by not making all efforts to support customer affordability through the ability to transact attributes of CPE-allocated resources. • The PD errs by basing its procurement cap on analysis that does not demonstrate a clear need for the technologies and amounts ordered:
o The PD errs in its definition of eligible resources;
o The PD bases its procurement caps on unsupported analysis; and o If the Commission foregoes CalCCA’s recommendation to revisit the need for central procurement in future IRP cycles, it must modify the PD to lower the procurement cap. • The PD fails to recommend the CPE retain an expert consultant to maximize state and federal funding opportunities.

Resolving these errors will ensure a well-functioning CPE process that mindfully considers its interactions with LSE procurement and determines needs based on well-supported analysis.

II. THE PROPOSED DECISION ERRS BY OMITTING NECESSARY DETAILS REGARDING THE RELATIONSHIP BETWEEN THE CPE’S PROCUREMENT AND THE LSE’S PLANNING AND PROCUREMENT ACTIVITIES
During the development of AB 1373, the Legislature recognized that:

Authorizing DWR to procure energy can have the unintended effect of reducing supply in the energy market and increasing prices overall (particularly in the currently constrained energy market).

These costs come home to roost on electric utility customer bills.

Additionally, market participants, including LSEs, electric POUs, and generators, may elect to delay procurement transactions so as to position themselves for procurement by DWR. In this regard, the state should tread carefully.8

Despite this caution, the PD creates uncertainty around how central procurement interacts with LSE procurement, which could exacerbate the negative consequences of central procurement 8 AB 1373.
4 conveyed by the Legislature. To reduce this uncertainty, the Commission should revise the PD as outlined in Sections II.A-C to clarify central procurement’s interactions with LSE procurement.

This is a necessary first step that must be taken prior to developing further operational and implementation details of cost and benefit allocation, as the PD commits to do before or during consideration of DWR contracts.
9 A. The Proposed Decision Must Recognize the Inherent Interactions Between Central Procurement and RCPPP that Cannot be Untangled
The PD finds that “CPE procurement should be kept in a separate category for purposes of consideration of an RCPPP in the future in this proceeding.”10 This finding introduces many questions that the PD leaves unanswered because central procurement and RCPPP procurement both intend to address GHG-driven procurement needs.
11 In addition, both must factor into reliability
planning to prevent costly over-procurement that could exacerbate the current affordability crisis facing the state’s customers. Central procurement will inevitably interact with LSE procurement.

The PD insufficiently addresses this interaction.

If CPE procurement is kept in a “separate category” from RCPPP procurement, it will be hard to determine how this procurement fits into the state’s overall procurement needs. If CPE procurement directives are part of the overall system reliability and GHG-reduction needs, then if the CPE fails to procure or elects not to procure based on the results of its solicitations, then the system will be short from a reliability and GHG-reduction perspective because the CPE’s failure to procure would not be accounted for in future need determinations in the RCPPP. Relatedly, if the CPE fails to procure or elects not to procure, it is unclear what steps will be taken to resolve the resulting shortfall, putting the RCPPP’s critically important objective of replacing order-by-order 9 Proposed Decision, COL 28.
10 Id., COL 22.
11 Id. at 2 and 50.
5 procurement requirements in jeopardy. If CPE procurement directives provide capacity in excess of the grid’s reliability need, then CPE procurement would contribute to the ongoing affordability crisis by procuring excess capacity from technologies that are not yet cost-effective.

Central procurement will inevitably interact with and significantly impact LSEs’ own procurement and planning processes. The Commission must modify the PD to document how the CPE process interacts with LSE procurement, particularly the RCPPP. In particular, the Commission should provide some indication of how and when it will provide certainty to LSEs to avoid unintentionally delaying LSE procurement.

To minimize impacts on LSEs’ planning and procurement processes, LSEs should receive frequent status updates on DWR’s central procurement activities, including information on the timing of solicitations and notices of project delays. The Commission should also elaborate on how it intends to minimize the use of the CPE once future LSE procurement is known and state affirmatively that attributes allocated to LSEs from CPE procurement can be used for compliance obligations such as RA and RPS. Simply stating that “it is logical to keep any CPE procurement as a result of this order separate and apart from any individual LSE requirements driven by the RCPPP,”12 is insufficient and leaves all parties unclear of how CPE procurement will impact LSEs’ own planning and procurement activities.

B. The Proposed Decision Errs by Neglecting to Include LSE Self-Procurement as a Step in the Process
AB 1373 provides a six-month window between the Commission determining there is a need for central procurement and the Commission requesting DWR to procure. The Legislature made clear that:

The intent for the six month window is to allow other LSEs the opportunity to procure their share of their load if they elect to do so. 12 Proposed Decision at 50.
6 This approach is a long-held principle of CCAs whose primary (if not exclusive) mission is to procure energy on behalf of their load.

Such an approach seems appropriate to ensure LSEs exercise their responsibility to procure resources for their load, prior to a state agency stepping in. In this regard, it’s possible DWR procurement may not ever be used, or perhaps only used when truly necessary because the resource was too difficult for any individual LSE, or a few LSEs, to procure.13
Despite this clear direction, the PD says nothing about LSEs' ability to procure their share of needed resources to reduce their allocations from DWR procurement. The Commission must modify the PD to create a process in which LSEs show contracts for any long lead-time (LLT) technologies specified in central procurement orders issued by the Commission to DWR. This should include any request made pursuant to this PD and in subsequent IRP cycles. If LSEs show these technologies, each LSE’s cost and benefit allocation should be reduced by their shown amount.

While the PD states that it targeted resources “intentionally different from resources already being procured by LSEs directly at sufficient volumes to result in market transformation,”14 the PD also acknowledges the LLT resources targeted in the PD may have higher costs than prevalent commercialized resources.15 In this PD, the Commission explicitly identifies a need for pre-commercial technologies with likely higher costs than conventional technologies. Because of these higher costs, it is logical that LSEs would not yet have procured these technologies without a clear indication from the Commission that there is a need for them, which had yet to occur in advance of the PD.

The opportunity to self-procure should be a feature of this initial central procurement order and future central procurement orders, which can be more easily incorporated into LSEs' planning and procurement activities if coordinated with the RCPPP process. Failure to allow self-procurement 13 AB 1373 at 14.
14 Proposed Decision at 49.
15 Id. at 3.
7 shifts costs onto the customers of early-moving LSEs, deterring early-moving LSEs from procuring quickly to accelerate reliability and decarbonization efforts.

As outlined in Section 4.5 of the PD, it will take time for DWR to begin its solicitations and contracting processes. Self-procurement can occur at least until the Commission issues its procurement request and DWR is ready to start its solicitations. For these reasons, the PD errs by neglecting to include an LSE self-procurement step in the CPE process. The Commission should revise the PD to allow LSEs to demonstrate procurement to lower their CPE allocations during the six-month window between the September 1, 2024, need determination and the procurement request to DWR.

C. The Proposed Decision Errs by Not Making all Efforts to Support Customer Affordability through the Ability to Transact Attributes of CPE-Allocated Resources
The PD states:
… this decision recognizes that electricity rates are rising, creating hardships for ratepayers. Though the DWR centralized procurement mechanism should help bring emerging technologies to scale, the cost of these investments will ultimately impact electricity bills.

Accordingly, all possible efforts should be made to contain costs, reduce ratepayer risk, and seek other sources of funding to reduce development costs and share in the long-term costs and benefits.16 To accomplish this critically important objective, the Commission must modify the PD to incorporate a key component of affordability: the ability for LSEs to transact attributes allocated from the CPE. Allowing LSEs to transact attributes enables LSEs to manage their resources and attributes in the most cost-effective manner, increasing market liquidity and putting downward pressure on prices for scarce supply. Allowing LSEs with excess attributes to offer to sell their surplus to other LSEs willing to buy will ensure the Commission achieves its objective of making all efforts to promote customer affordability, without jeopardizing reliability and state policy goals. 16 Proposed Decision at 3.
8 The PD states, that “[f]urther operational and implementation details of the allocation of costs and benefits of CPE procurement to LSEs will be handled in this proceeding or its successor before or during consideration of actual contracts to be signed by DWR.”17 The Commission should modify the PD to explicitly include CPE allocation transactions within the scope of issues that will be resolved before DWR contracting opportunities.

III. THE PROPOSED DECISION ERRS BY BASING ITS PROCUREMENT CAP ON

ANALYSIS THAT DOES NOT DEMONSTRATE A CLEAR NEED FOR THE

TECHNOLOGIES AND AMOUNTS ORDERED
The PD finds an initial need determination of 10.6 gigawatts (GW) of nameplate capacity of the following technologies: up to 7.6 GW of offshore wind (OSW), up to 1 GW of enhanced geothermal systems (EGS), up to 1 GW of multi-day long-duration energy storage (LDES), and up to 1 GW of LDES with a discharge period of at least 12 hours. 18 The PD defines the technologies
eligible for central procurement in a way that will not mitigate risk and ensure cost containment. It also bases its procurement caps on unsupported conclusions that may result in crowding out a significant amount of LSE procurement for the foreseeable future. Procurement caps that are too high result in higher levels of uncertainty. This uncertainty will result in more risks for LSEs trying to manage their portfolios with uncertain amounts of attributes and associated costs allocated to them. It also increases the potential for developers to reduce their participation in LSE solicitations in favor of uncertain central procurement opportunities.

For these reasons, the Commission should not find a need for central procurement for the September 1, 2024, deadline, and instead, work on (1) building a record that better informs the need for central procurement, and (2) refining the central procurement process within the context of the forthcoming RCPPP. If the Commission foregoes this recommendation and makes a need 17 Proposed Decision, COL 28. 18 Id. at 2.
9 determination for central procurement on September 1, 2024, the Commission should only direct the procurement of the minimum amount of OSW in federal leased areas needed to establish the requisite infrastructure to kickstart the development (1 GW). 19 The Commission should not direct
central procurement of EGS or LDES.

A. The Proposed Decision Errs in Its Definition of Eligible Resources The PD states it focuses central procurement on technologies the Commission believes “could be important to the electricity sector as a whole in achieving California’s Senate Bill 100 (SB 100) (De León, Chapter 312, Statutes of 2018) goals by 2045, but which will be inherently more expensive due to their emerging nature and the fact that they are not currently commercially available at competitive prices.”20 This definition allows for the possibility of ordering central procurement of resources with excessive risks and a low benefit-to-cost ratio, resources that do not meet the statutory definition of LLT for the purposes of central procurement, or resources that LSEs have already demonstrated the ability to procure.

EGS and LDES are not good candidates for central procurement. First, LDES resources do not consistently meet the statutory definition of LLT (requiring 5 years for construction and development), depending on the project. Additionally, there is no evidence that LSEs cannot and would not procure these resources if they are available and cost-effective. LSEs have already demonstrated the ability to procure EGS, in addition to conventional geothermal projects, and LDES projects, both individually and jointly. The Commission has yet to conduct a cost-benefit analysis on these technologies, however, so it is unknown whether central procurement of these technologies has 19 Administrative Law Judge’s Ruling Seeking Comments on Need and Process for Centralized Procurement of Specified Long Lead-Time Resources, R.20-05-003 (Apr. 26, 2024) at 17-20: This Ruling established 1 GW as the "estimated minimum viable project size” and finds 1 GW as the most likely amount to maximize ratepayer benefits under most scenarios.
20 Proposed Decision at 37.
10 greater net benefits than an alternative combination of resources with an equivalent profile procured by LSEs. Finally, the Commission defines the need specifically for EGS and non-lithium-ion or pumped storage hydro LDES and splits the LDES requirement into multi-day and 12+ hour LDES.

This definition carves out an overly specific need that may only be filled by a few developers when the actual need could have been filled by a broader set of technologies, including those LSEs have proven the ability to procure already. The result is the potential for non-competitive results to DWR’s solicitation for a need that is too targeted. For these reasons, the Commission should not direct central procurement of EGS or LDES,
OSW may be the only reasonable candidate for central procurement. LSEs have demonstrated that size is not a barrier to procurement (e.g., OOS-wind procurement). Rather, it is the significant infrastructure investment required for OSW development (e.g., port infrastructure, transmission development, etc.) that presents hurdles that must be overcome regardless of the procuring entity. Additionally, while the cost-effectiveness of OSW is still questionable, it is possible that an alternative combination of resources with an equivalent profile could serve the same need at a potentially lower cost. Still, emerging technologies are typically high-risk, and central procurement may make sense when investments will result in spurring future development opportunities for LSEs, enhancing development efficiencies, or promoting economies of scale.

To tighten the definition of eligible resources in advance of ordering central procurement, the Commission should build a record (1) demonstrating that the technologies identified can help the state meet SB 100 goals at costs, inclusive of the market transformation costs, that are lower than those for meeting SB 100 goals with an alternative portfolio of current technologies procured by 11 LSEs and (2) defining “5 years for construction and development,”21 and demonstrate in the record that these technologies necessarily take longer than five years to construct and develop. The analysis in the record thus far does not adequately demonstrate the estimated costs of central procurement are lower than an alternative portfolio procurement by LSEs. Nor does it conclude that LDES technologies have construction and development times of more than five years or demonstrate net benefits for these technologies. 12+-hour LDES and multi-day LDES have yet to be properly modeled in the preferred system plan (PSP) due to a lack of sufficient cost information. Building a record to support these findings before ordering central procurement will ensure the Commission appropriately manages the risks of central procurement of emerging technologies and adheres to the statutory definition of LLT resources.

B. The Proposed Decision Bases Its Procurement Caps on Unsupported Conclusions In justifying the procurement caps ordered in the PD, the Commission concludes:

It is reasonable to ask DWR to solicit approximately half of the resource need identified in the most recent adopted PSP portfolio in D.24-02-047 for LDES and geothermal, in order to facilitate a downpayment on technologies necessary to achieve SB 100 goals, while still leaving room for LSEs to procure the technologies individually, after costs are reduced and market transformation is underway.22
It also concludes:

It is reasonable to ask DWR to solicit for 7.6 GW nameplate of OSW, which signals a strong interest in developing the resource, represents the level beyond which our staff cost-benefit analysis shows the potential for higher risks to ratepayers, is sufficient to foster cost savings as the resource is developed at scale, and avoids the potential for market power issues.23
21 The definition of a resource’s construction and development must not include interconnection and transmission development to ensure the focus of central procurement is truly on resources themselves that are LLT.
22 Proposed Decision, COL 17.
23 Proposed Decision, COL 18.
12 The PD does not support these conclusions with evidence in the record indicating that the deployment of the scale identified in the PD will result in market transformation sufficient to bring costs down below the costs of meeting SB 100 targets with conventional technologies. Instead, the PD bases its procurement amounts on a PSP with outdated cost assumptions for OSW, a cost-benefit analysis that shows negative net benefits in most scenarios at the volume of OSW ordered, and no cost-benefit analysis for LDES or EGS.

Setting a procurement cap that may or may not be cost-effective without working on infrastructure issues will not result in sufficient room for LSEs to procure on their own and may result in market power issues. Simply shifting the procurement responsibility from LSEs to a CPE does not resolve issues with transmission, port infrastructure, and interconnection. Therefore, the market will likely experience increased costs and limited project availability as a result of the Commission's recommendation that these technologies be considered by DWR for central procurement. With project interconnection timelines now exceeding seven years from interconnection request to commercial operation in many cases,24 the Commission's central procurement directive may result in merely cutting off direct LSE procurement of these technologies for years into the future.

Ordering roughly 50 percent of OSW capacity in the PSP is likely too high compared to what is needed to transform the OSW industry and would very likely stifle developers' willingness to offer projects to LSEs. As it stands, the need determination in the PD is an after-the-fact analysis of plans completed by LSEs that did not have advanced notice that these three categories of technologies 24 The time it takes between interconnection request and interconnection agreement can take over two years: https://www.caiso.com/documents/mergedpresentations-resourceinterconnectionfair-march032021.pdf.

The time from interconnection agreement to commercial operations takes over six years on average: Lawrence Berkely National Lab, Queued Up: 2024 Edition, Slide 39: https://emp.lbl.gov/sites/default/files/2024- 04/Queued%20Up%202024%20Edition_R2.pdf.
13 were needed or required. The PD states, “[t]he November 1, 2022 individual LSE IRP filings, along with their August 1, 2023 and December 1, 2023 procurement data filings, do not show LLT resources under contract to LSEs in sufficient quantities to achieve scale and cost reductions in the long run.” It provides no compelling evidence, however, identifying the "sufficient quantity” of LLT resources necessary “to achieve scale and cost reduction in the long run." The Department of Energy’s recent Pathways to Commercial Liftoff report for Offshore Wind report25 suggests the Commission’s need determination of 7.6 GW of OSW significantly exceeds the amount of early commercial deployments necessary to scale-up emerging technologies.26 Therefore, if the Commission foregoes the recommendation to reconsider central procurement needs in a future IRP cycle, the Commission must also consider the most up-to-date information provided by the LSEs on their procurement activity, including the June 1, 2024, IRP filings. The Commission should account for planned procurement that would result in LSEs contracting at a later time and still bringing those resources to commercial operation in time to meet their needs. As described in section II.B, it must also provide LSEs the opportunity to lower their share of central procurement amounts during the six months between need determination and procurement request. Only after a need determination and procurement request would LSEs have a clear indication of the need.

C. If the Commission Foregoes CalCCA’s Recommendation to Revisit the Need for Central Procurement in Future IRP Cycles, it Must Modify the Proposed Decision to Lower Procurement Cap
Sections III.A and III.B above demonstrate the need to continue building the record before ordering DWR to conduct central procurement of LLT resources. If the Commission foregoes 25 United States Department of Energy. Pathways to Commercial Liftoff: Offshore Wind (Apr. 2024). 26 The Department of Energy identifies a need for 10-15 GW nationwide of early commercial deployments to ultimately unlock over 100 GW of scale-up, representing roughly 10% of the target. 14 additional record development before ordering DWR procurement, the Commission must direct the procurement of only the minimum amount of OSW in federal leased areas needed to establish the requisite infrastructure to kickstart the development (1 GW). The central procurement of OSW could benefit from coordinating procurement and infrastructure development, but only in modest amounts, given the results of the Commission’s cost-benefit analysis27 and the negative interactions central procurement can have with LSE procurement.

One GW of OSW central procurement is most consistent with the cost-benefit analysis in the ALJ Ruling, which suggests the highest potential net benefits at lower levels of OSW procurement.

Higher amounts of OSW central procurement or central procurement of technologies beyond OSW would overly concentrate SB 100's success on the CPE endeavor, ignoring the successes of LSEs procuring to meet a clearly identified and communicated need, adding competition for scarce resources and interconnection capacity, and undermining affordability.

The higher the potential central procurement cap, the harder it is for LSEs to plan around and the greater the degree of risk associated with CPE failure. Certainty and transparency around DWR’s central procurement is imperative to minimize negative impacts and interactions with LSE procurement processes. The larger the potential size of the CPE procurement, the greater the risk for LSEs and the harder it is for LSEs to manage their own portfolios given the uncertainty in DWR’s final contracted volumes and the LSE’s allocation. Given the importance of providing certainty for LSE procurement planning and risk mitigation, the central procurement cap in this initial need determination should be a modest hard cap. This amount can be revised upward in future IRP cycles 27 The Commission’s OSW cost-benefit analysis finds, even 1-3 GW of OSW procurement may come at a net cost, though total ratepayer impact would be small. It finds “[l]ower amounts of offshore wind generally minimize[es] total ratepayer cost and risk” and “[i]nitial OSW procurement [of 1-3 GW] can support market transformation with limited ratepayer risk.” Analysis for Centralized Procurement of Specified Long Lead-Time Resources (April 2024), at 41.
15 after considering the most up-to-date LSE planning and procurement information once LSEs have had an opportunity to develop their plans in light of this newly identified need. The Commission must render formal decisions for any subsequent need determinations in future IRP cycles to ensure parties have sufficient ability to vet the need determination, supporting analysis, and resulting allocations.

IV. THE PROPOSED DECISION FAILS TO RECOMMEND THE CPE RETAIN AN

EXPERT CONSULTANT TO MAXIMIZE STATE AND FEDERAL FUNDING

OPPORTUNITIES
CalCCA strongly supports the Commission’s goal to make “all possible efforts… to contain costs, reduce ratepayer risk, and seek other sources of funding to reduce development costs and share in the long-term costs and benefits.”28 To ensure the PD results in a process that takes advantage of all possible sources of funding to reduce costs, the Commission should revise the PD to recommend that DWR have dedicated staff members or consultants who investigate grant opportunities and assist potential project developers in reducing costs by maximizing the use of funding opportunities in its centralized procurement efforts.

V. CONCLUSION
CalCCA appreciates the opportunity to submit these comments and requests the adoption of the recommendations proposed herein. For all the foregoing reasons, the Commission should modify the Proposed Decision as provided in Appendix A.

Respectfully submitted,
Evelyn Kahl,
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
August 8, 2024
28 Proposed Decision at 3.

Appendix A-1

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

PROPOSED DECISION DETERMINING NEED FOR CENTRALIZED

PROCUREMENT OF LONG LEAD-TIME RESOURCES

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

2. The resource types considered for a need determination for centralized procurement are geothermal, LDES, OOS wind, and is OSW.

4. EGS is an emerging technology distinct from conventional geothermal, and is the subject of an initiative at DOE called “Enhanced Geothermal Shot” designed to reduce the costs of EGS.

However, the costs and benefits are not known at this time and the length of time for construction and development has not been demonstrated to exceed five years.

5. 12+-hour LDES and multi-day LDES are emerging technologies that are not yet sufficiently available with known costs to be modeled in previous PSP portfolios adopted by the Commission.

Therefore, proxies have been used. As such, the cost-effectiveness of these resources is not known.

8. As of this decision, almost no LSEs have EGS, 12+-hour LDES, multi-day LDES, or OSW projects under contract. Those LSEs that do have these types of projects do not have any significant volumes under contract relative to the size of the resource potential or in enough quantities to spur market transformation. Given the recent development in EGS, LDES, and OSW, additional time is needed for LSEs to pursue contracting of these resources before determining a central procurement need.

Appendix A-2

12. The November 1, 2022, individual LSE IRP filings did not represented the CCAs’ opportunity to offer proposals under Section 454.51(d) requirements, because the Commission had not yet identified a need for centrally procured technologies.

13. The November 1, 2022, individual LSE IRP filings, along with their August 1, 2023, and December 1, 2023, procurement data filings, do not show LLT resources under contract to LSEs in sufficient quantities to achieve scale and cost reductions in the long run. Any new efforts in procurement plans by the LSEs should be used to update the need analysis prior to finalizing any central procurement.

CONCLUSIONS OF LAW

7. The Commission should reevaluate the need for centralized procurement of LLT resources in each IRP cycle, in concert with evaluating the need for LSE procurement in the RCPPP, when considering the adoption of a PSP portfolio.

10. Resources that are important to reducing the overall emissions in the electricity sector, but which may not compete favorably in price against other resources, should be considered for centralized procurement after LSEs have an opportunity to demonstrate contracts for the newly identified need.

14. The Commission should not, at this time, ask DWR to solicit for resource types that are already being widely procured in significant volumes by numerous individual LSEs.

16. LDES requested for DWR to solicit for centralized procurement should include 12+- hour LDES and multi-day LDES, but not lithium-ion batteries or PSH.

17. It is reasonable to ask DWR to solicit approximately half of the resource need identified in the most recent adopted PSP portfolio in D.24-02-047 for LDES and geothermal, in order to facilitate a downpayment on technologies necessary to achieve SB 100 goals, while still Appendix A-3
leaving room for LSEs to procure the technologies individually, after costs are reduced and market transformation is underway.

18. It is reasonable to ask DWR to solicit for 7.6 1 GW nameplate of OSW at most, which signals a strong interest in developing the resource and establishing the requisite infrastructure to kickstart this development, represents the level beyond which our staff cost-benefit analysis shows the potential for higher risks to ratepayers, is sufficient to foster cost savings as the resource is developed at scale by LSEs, and avoids the potential for market power issues.

19. Centralized procurement of LLT resources should be considered by the Commission in a separate category from concert with individual LSE procurement resulting from the RCPPP.

20. Any CPE procurement should not count toward the requirements of D.21-06-035, D.23-02-040, or D.24-02-047, but may count for future RCPPP procurement requirements.

21. The Commission should evaluate in subsequent AB 1373 need determinations the LSE progress toward the D.21-06-035 requirements for procurement of 1 GW of high-capacity-factor clean LLT resources and consider whether additional CPE procurement of conventional geothermal resources is necessary.

22. CPE procurement should be kept in a separate category for purposes of consideration of an RCPPP in the future in this proceeding.

23. AB 1373 does not provides an opportunity for LSEs to opt out of centralized conduct their share of procurement during the six months between when the Commission makes its need determination and once the Commission has made its procurement request need determination.

LSEs subject to the Commission’s IRP purview should not be allowed to opt out of paying for their share of centralized procurement.

Appendix A-4

28. Further operational and implementation details of the allocation of costs and benefits of CPE procurement to LSEs, including the ability for LSEs to transact allocations, will be handled in this proceeding or its successor before or during consideration of actual contracts to be signed by DWR.

40. The Commission should not need to render a second formal decision during the six-month window after September 1, 2024, and after any subsequent need determination in future IRP cycles. The request for procurement after the Commission’s formal need determination in a decision may come in the form of a letter to DWR from the Commission president and/or the assigned Commissioner to the IRP rulemaking, consistent with the provisions of this decision.

New: The Commission should recommend that DWR retain an expert consultant or staff to advise on all alternative sources of funding, like federal and state funds, to contain costs of central procurement.

New: Net benefits that demonstrate the technologies identified can help the state meet SB 100 goals at costs, inclusive of the market transformation costs, that are lower than those for meeting SB 100 goals with an alternative portfolio of conventional technologies should be an explicit and important criterion for the selection of resources to be centrally procured.

ORDERING PARAGRAPHS

1. The Commission has evaluated eligible resource types under Public Utilities Code Section 454.52(h)(1)-(2) categories and has determined that there is a need for centralized procurement through competitive solicitations by the Department of Water Resources (DWR) as a Central Procurement Entity for the following resources, in nameplate capacity, with energy deliveries and/or capacity online between June 1, 2031 and June 1, 2037. DWR is not required to procure all of the below resources and may procure as little as zero, depending on the reasonableness of prices offered by developers:

Appendix A-5
(a) A maximum of 1,000 megawatts (MW) of Enhanced Geothermal Systems, as defined by the United States Department of Energy's “Enhanced Geothermal Shot” initiative;
(b) A maximum of 1,000 MW of long-duration energy storage (LDES) that can discharge for 12 hours or more that does not employ lithium-ion batteries or pumped storage hydroelectric (PSH) technologies;
(c) A maximum of 1,000 MW of multi-day LDES that does not employ lithium-ion batteries or PSH technologies; and
(ad) A maximum of 7,600 1,000 MW of offshore wind.

3. After the completion of the self-procurement period, Aall load-serving entities with obligations under the integrated resource planning process of the Commission related to Public Utilities Code Sections 454.51 and 454.52 shall be required to pay for their proportional share, adjusted for self-procurement, of any resources determined to be needed by the Commission and centrally procured by the Department of Water Resources for the life of the contracts, once approved by the Commission.

4. The costs and benefits of any procurement of offshore wind and enhanced geothermal systems shall be allocated annually on the basis of forecast energy load share, for the life of each contract.

5. The costs and benefits of any procurement of long-duration energy storage shall be allocated annually to each transmission access charge area based on forecast 12-month peak load, and then further allocated to each load-serving entity’s customers in the same manner as the Cost Allocation Mechanism adopted in Decision 06-07-029, for the life of each contract.

Appendix A-6
New: The Commission recommends that the Department of Water Resources retain an expert consultant or staff member to advise on all alternative sources of funding, such as state and federal funding to contain the costs of central procurement.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue
Electric Integrated Resource Planning and
Related Procurement Processes.

R.20-05-003
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY COMMENTS

ON THE PROPOSED DECISION DETERMINING NEED FOR CENTRALIZED

PROCUREMENT OF LONG LEAD-TIME RESOURCES
Evelyn Kahl,
General Counsel and Director of Policy
Lauren Carr,
Senior Market Policy Analyst
Eric Little,
Director of Regulatory Affairs

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
1121 L Street, Suite 400
Sacramento, CA 95814
Telephone: (510) 980-9459
E-mail: [email protected]
August 13, 2024
FILED
08/13/24
04:59 PM
R2005003
ii

TABLE OF CONTENTS
I. THE COMMISSION SHOULD REJECT PARTIES’ RECOMMENDATIONS

TO REVISE THE PD TO ORDER HIGHER AMOUNTS OF CENTRAL
PROCUREMENT ................................................................................................................1 II. CALWEA’S RECOMMENDATION THAT THE COMMISSION EXPLICITLY

ASK DWR TO CONSIDER PROCUREMENT OF THE CADEMO PROJECT

ILLUSTRATES THE NEGATIVE CONSEQUENCES OF CENTRAL
PROCUREMENT AND MUST BE REJECTED ...............................................................3 III. THE COMMISSION MUST REJECT PARTIES’ RECOMMENDATIONS

THAT PREVENT LSE PARTICIPATION IN THE PROCUREMENT REVIEW GROUP ................................................................................................................................4 IV. PARTIES’ COMMENTS AFFIRM THAT A FUTURE TRACK OF THIS PROCEEDING TO DISCUSS COST ALLOCATION IS WARRANTED .......................5 V. CONCLUSION ....................................................................................................................5 iii

SUMMARY OF RECOMMENDATIONS
• The California Public Utilities Commission (Commission) should reject parties’ recommendations to revise the Proposed Decision to order higher amounts of central procurement;
• California Wind Energy Association’s recommendation that the Commission explicitly ask Department of Water Resources to consider procurement of the CADEMO project illustrates the negative consequences of central procurement and must be rejected; • The Commission must reject parties’ recommendations that prevent load-serving entity participation in the procurement review group; and
• Parties’ comments affirm that a future track of this proceeding to discuss cost allocation is warranted.

CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY COMMENTS

ON THE PROPOSED DECISION DETERMINING NEED FOR CENTRALIZED

PROCUREMENT OF LONG LEAD-TIME RESOURCES
The California Community Choice Association (CalCCA) submits these Reply Comments pursuant to Rule 14.3 of the California Public Utilities Commission (Commission) Rules of Practice and Procedure1
on the proposed Decision Determining Need for Centralized Procurement of Long Lead-Time Resources2 (Proposed Decision or PD), dated July 19, 2024.

I. THE COMMISSION SHOULD REJECT PARTIES’ RECOMMENDATIONS TO

REVISE THE PD TO ORDER HIGHER AMOUNTS OF CENTRAL PROCUREMENT Some parties provided opening comments3 recommending the Commission increase its initial need determination.4 While these parties provide no support justifying their recommendations, other parties rightly note that the Commission did not find a clear need for the amounts and technologies ordered in the PD,5
load-serving entities (LSEs) have already demonstrated the ability to procure long-lead-time (LLT) resources,6 and the amounts ordered in the PD create risks of over- or under-procurement.7 For the reasons described below, the PD’s need determination is already too high. The Commission should dismiss parties’ recommendations to increase its initial need determination and instead recommend DWR consider central procurement of, at most, 1 gigawatts (GW) of offshore wind (OSW) only after considering updated LSE procurement statuses.

First, the Commission has not clearly demonstrated a need for enhanced geothermal systems (EGS) or long-duration energy storage (LDES) central procurement. Unlike for OSW, the Commission has not conducted a cost-benefit analysis for these technologies, and as noted by several parties, 8 the
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 Proposed Decision Determining Need for Centralized Procurement of Long Lead-Time Resources, Rulemaking (R.) 20-05-003 (July 19, 2024). 3
All references herein to party comments are to the Opening Comments filed in this proceeding, R.20-05-003, on August 8, 2023.
4 Offshore Wind California Opening Comments at 2, RWE Offshore Wind Holdings LLC at 2, Environmental Defense Fund (EDF) Opening Comments at 9-10. 5 Pacific Gas and Electric Company (PG&E) Opening Comments at 2-3 and 5-6, and Southern California Edison Company (SCE) Opening Comments at 3-6. 6 SCE Opening Comments at 6-8, and the Public Advocates Office of the California Public Utilities Commission (Cal Advocates) Opening Comments at 2-3.
7 SCE Opening Comments at 9-11. 8
Cal Advocates Opening Comments at 5, PG&E Opening Comments at 6, and SCE Opening Comments at 3-6.
2 Commission has not found a need for EGS or LDES in the preferred system plan. In addition, these technologies have already been offered in LSEs' own solicitations,9 and LSEs have already contracted for EGS, demonstrating that LSEs can procure these LLT resources without the California Department of Water Resources (DWR) procuring them first.
10 Requesting DWR procure these resources in
competition with LSEs will make it even more challenging for LSEs to meet existing and future compliance requirements.

Second, as noted by PG&E and SDG&E, the amount of OSW included in the PD’s need determination is not aligned with the results of the cost-effectiveness analysis.11 Increasing the need determination for OSW would exacerbate the PD’s error by increasing the risk central procurement will not be cost-effective. RWE OSW Holdings LLC’s suggests that an increased need determination for central procurement is needed to ensure “market transformation.”12 Market transformation will result from infrastructure development, which is necessary to support any amount of procurement, whether procured via LSEs or DWR. The larger the central procurement need determination, the higher the risk of over or under-procurement. As SCE notes:

Because no LSE can know what specific amount...the CPE will procure (much less come on-line), it is impossible to determine whether all, some, or none of the 7,600 MW procurement target will be relied upon to meet the state’s GHG and/or reliability requirements. LSEs would have no ability to determine or plan for the position when they make procurement decisions. Depending on an LSE’s assumptions, this could result in over- or under-procurement through no fault of the LSEs, especially since the proposed OSW target is so large and the actual amount of OSW to be procured by DWR is uncertain.13
The Commission should keep procurement amounts small to mitigate risk and costs while still driving infrastructure development.

EDF recommends higher procurement stating, “DWR, unlike individual LSEs, can temper ratepayer impacts by using low-cost government bonds, waiting to begin recovering the cost of resources from individual LSEs and customers until the projects provide energy benefits, and 9 SCE Opening Comments at 7-8 and San Diego Gas and Electric Company (SDG&E) Opening Comments at 4.
10 SCE Opening Comments at 6-8.
11 PG&E Opening Comments at 2 and SDG&E Opening Comments at 6. 12 RWE Offshore Wind Holdings LLC Opening Comments at 2. 13 SCE Opening Comments at 10.
3 spreading out the cost of this development across decades.”14 DWR financing the cost of new resource procurement will not reduce the total cost. In fact, it will increase them by the interest paid on the bonds.

For these reasons, the Commission should reject parties’ recommendation to increase the PD’s need determination. It should instead recommend DWR consider central procurement of, at most, 1 GW of OSW only after considering updated LSE procurement statuses, as recommended in CalCCA’s opening comments.15
II. CALWEA’S RECOMMENDATION THAT THE COMMISSION EXPLICITLY

ASK DWR TO CONSIDER PROCUREMENT OF THE CADEMO PROJECT

ILLUSTRATES THE NEGATIVE CONSEQUENCES OF CENTRAL

PROCUREMENT AND MUST BE REJECTED
CalWEA recommends the Commission “explicitly ask DWR to consider procurement of the CADEMO project.”16 This recommendation runs directly counter to the Commission’s well-reasoned intent “not to interfere with any of these efforts or penalize early action by some LSEs for some resources.”17 It also highlights exactly why CalCCA,18 other parties, 19 and the Legislature20 have
asked the Commission to take a cautious approach to ordering central procurement. For the reasons described below, avoiding interference with LSE procurement is essential, and the Commission should reject CalWEA’s recommendation to explicitly interfere.

If the Commission were to explicitly recommend DWR explore procurement of resources LSEs already have a demonstrated interest in, LSEs may become hesitant to take future proactive actions to procure in the event their procurement activities end up being for naught. In addition, when central procurement overlaps with LSE procurement, either in terms of technology or timing, the Commission introduces additional competition into a market with scarce supply. CADEMO and all other projects, whether eligible for central procurement or not, will contract with whichever entity will provide them with the best revenue opportunity. If central procurement adds extra demand for 14 EDF Opening Comments at 2.
15 CalCCA Opening Comments at 13-15. 16 California Wind Energy Association (CalWEA) Opening Comments at 3. 17 Proposed Decision at 39.
18 CalCCA Opening Comments. 19 SCE Opening Comments at 6-8 and 9-11, CC Power Opening Comments at 6-7. 20 AB 1373 Senate Committee on Energy, Utilities and Communications Bill Analysis (Version Aug. 31, 2023, published Sept. 6, 2023).
4 resources in scarce supply that LSEs are already interested in procuring, it will unnecessarily compete with LSE procurement and drive prices up.

As the PD notes, California Community Power (CC Power) has already initiated an RFI for OSW, resulting in a memorandum of understanding (MOU) with the CADEMO project.21 Through the MOU, CC Power “aims to learn about the drivers of key costs of [OSW] development” and “apply for grants, incentives, and other support to minimize the cost of offtake...”22 The efforts CC Power and CADEMO will undertake are “intended to drive parties toward the potential for a power purchase agreement with the energy benefits and costs flowing to the participating CC Power member CCAs.”23 By asking the Commission to direct DWR to explore procurement of a specific resource, CalWEA’s recommendation asks the Commission to disregard existing LSE procurement activities. The Commission should not introduce central procurement opportunities for resources LSEs are already considering procuring.

III. THE COMMISSION MUST REJECT PARTIES’ RECOMMENDATIONS THAT

PREVENT LSE PARTICIPATION IN THE PROCUREMENT REVIEW GROUP Invenergy objects to the composition of the Procurement Review Group (PRG) recommending that instead, PRG participants may not be involved in any market activities.24 The Commission should reject this change. It is not clear what it means to “be involved in market activities.” It is also not clear that this would only include those responsible for executing transactions (i.e., those negotiating contracts) or if it would expand to personnel working in spaces related to markets, such as legal staff or regulatory staff that regularly engage in rules governing bilateral and organized CAISO markets. The Commission's objective is to have personnel with sufficient familiarity to be able to provide meaningful input to DWR on their procurement approach, process, and contract execution. 25 Invenergy’s unclear
“involved in market activities” definition could leave the PRG with insufficient experience.

A better model for participation in the PRG is that provided by PG&E which would:
permit LSE representatives, including employees, contractors, and consultants, to participate in the procurement group so long as they are not “directly responsible” for discharging any LSE's role and 21 Proposed Decision at 25.
22 https://cademo.net/california-community-power-x-cademo/. 23 Id. 24 Invenergy Opening Comments at 5-6. 25 Proposed Decision at 58, “we are persuaded that LSEs should have representation on the procurement group, both because they may have expertise to bring to the table and because their ratepayers will ultimately be paying the costs of DWR’s contracts.”
5 responsibilities with respect to procurement, sales, or portfolio management or conducting any relevant active or open solicitations for an LSE. To effectuate this, PG&E proposes that "directly responsible" be defined as follows: the person’s role involves making formal recommendations to Executives/Officers or a governing board of the LSE or direct decision-making authority regarding procurement or sales or development of strategies for active management of the LSE’s portfolio.26
IV. PARTIES’ COMMENTS AFFIRM THAT A FUTURE TRACK OF THIS PROCEEDING

TO DISCUSS COST ALLOCATION IS WARRANTED
The PD rules in favor of SCE’s proposal to allocate EGS and OSW on the basis of energy load share served among LSEs.
27 PG&E commented, “the Proposed Decision should be modified to correct inconsistencies between the new statewide NBCs and to ensure feasible implementation. Specifically, for energy-producing resources, the PD states that the allocation of costs be “done at the individual LSE level, without the need to allocate by IOU TAC area first.”28 While CalCCA understands the concerns expressed by PG&E, the current PD does not require modification as the PD already states, “Further implementation details to operationalize this policy may need to be addressed by the Commission in this proceeding prior to or during consideration of actual projects to be contracted by DWR.”29
CalCCA notes that within proceeding R.23-01-007, to implement the extension of operation of Diablo Canyon, the investor-owned utilities (IOU), CCAs, and ESPs are currently working together to develop a methodology to allocate the green-house gas-free attribute on an energy basis throughout the entire state consistent with the allocation of costs that are allocated to all LSEs in the state. This PD should not foreclose on the options that the Commission will evaluate in its “further implementation details.” Since the state has rarely done any procurement for the benefit of all customers across all three IOU areas in the past, more time is needed to evaluate the best solutions to the issues once more record has been developed.

V. CONCLUSION
CalCCA appreciates the opportunity to submit these Reply Comments and requests adoption of the recommendations proposed herein.
26 PG&E at 10-11 (footnote omitted).
27 Proposed Decision at 55. 28 PG&E Opening Comments at 13-14 (footnote omitted). 29 Proposed Decision at 55.
6 Respectfully submitted,
Evelyn Kahl,
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
August 13, 2024
t

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.23-10-011
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S OPENING
COMMENTS ON ADMINISTRATIVE LAW JUDGE’S RULING
MODIFYING TRACK 2 SCHEDULE
Evelyn Kahl,
General Counsel and Director of Policy
Lauren Carr,
Senior Market Policy Analyst
Eric Little,
Director of Regulatory Affairs

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
1121 L Street, Suite 400
Sacramento, CA 95814
Telephone: (510) 980-9459
E-mail: [email protected]
August 9, 2024
FILED
08/09/24
04:59 PM
R2310011
i

TABLE OF CONTENTS
I. INTRODUCTION ...............................................................................................................1 II. LOLE RECOMMENDATIONS ..........................................................................................3 A. Revisit Changes to the PRM Level When the Commission’s Tools and Approach are Stable .................................................................................................3 B. Align the Commission’s Framework with the Primary Questions of the RA Program .............................................................................................................4 C. Maintain a Single Annual PRM Until the Commission’s Study Methodology is Sufficient to Evaluate Monthly or Seasonal PRMs .......................5 D. Incorporate Uncertainty of the Load Forecast, Based on Observed IEPR Forecast Errors, into SERVM Forecast Error Parameters ..............................7 E. Ensure the Contribution of Storage to Reliability is Consistently Represented ..............................................................................................................7 F. Evaluate Whether the Commission’s Choice to Stress System with Flat Load Materially Impact PRM Results .....................................................................7 III. CPE RECOMMENDATIONS.............................................................................................8 A. Refrain from Repurposing or Dismantling the Local RA CPE at this Time .........................................................................................................................8 B. Do Not Shift the CPEs’ Role to a Backstop Role at this Time ..............................10 C. Reject MRP’s Proposal to Direct CPEs to Terminate Contracts ...........................11 D. Reject PG&E and SCE’s Proposals for Modifying the Self-Showing Process ...................................................................................................................12 E. Work with the CAISO to Determine How Best to Harmonize Local RA Requirements with SOD ..................................................................................15 IV. CONCLUSION ..................................................................................................................16 ii

SUMMARY OF RECOMMENDATIONS
• Revisit changes to the Planning Reserve Margin (PRM) level when the California Public Utilities Commission’s (Commission) tools and approach are stable; • Align the Commission’s framework with the primary questions of the Resource Adequacy (RA) program;
• Maintain an annual PRM until the Commission’s study methodology is sufficient to evaluate monthly or seasonal PRMs;
• Incorporate uncertainty of load forecast, based upon observed Integrated Energy Policy Report forecast errors, into the Strategic Energy Risk Valuation Model forecast error parameters;
• Ensure the contribution of storage to reliability is consistently represented; • Evaluate whether the Commission’s choice to stress the system with flat load materially impacts the PRM result;
• Refrain from repurposing or dismantling the local RA central procurement entity (CPE) at this time;
• Do not shift the CPEs’ role to a backstop role at this time; • Reject Western Power Trading Forum’s proposal to shift the CPEs’ role to a backstop role at this time;
• Reject Middle River Power LLC’s proposal to direct CPEs to terminate contracts; • Reject Pacific Gas and Electric Company’s and Southern California Edison Company’s proposals for modifying the self-showing process; and • Work with California Independent System Operator Corporation to determine how best to harmonize local RA requirements with slice-of-day.

BEFORE THE PUBLIC UTILITIES COMMISSION

R.23-10-011
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S OPENING
COMMENTS ON ADMINISTRATIVE LAW JUDGE’S RULING
MODIFYING TRACK 2 SCHEDULE
California Community Choice Association1 (CalCCA) submits these Opening Comments pursuant to the Administrative Law Judge’s Ruling Modifying Track 2 Schedule 2 (Ruling), dated June 26, 2024. The Ruling seeks comments on all proposals filed.

I. INTRODUCTION
CalCCA appreciates the efforts of Energy Division staff to develop its Loss of Load Expectation (LOLE) Study3 and Central Procurement Entity (CPE) Report4 and the efforts of parties to advance thoughtful proposals for Track 2 scope items. The LOLE Study, specifically 1 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. 2 Administrative Law Judge’s Ruling Modifying Track 2 Schedule, Rulemaking (R.) 23-10-011:
https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M534/K332/534332050.PDF. 3 Administrative Law Judge’s Ruling on Energy Division’s Loss of Load Expectation Study, R.23- 10-011 (July 22, 2024) (LOLE Study):
http://docs.cpuc.ca.gov/SearchRes.aspx?DocFormat=ALL&DocID=536273741. 4 Administrative Law Judge’s Ruling on Energy Division’s Central Procurement Entity Framework Report, R.23-10-011 (June 5, 2024) (CPE Report):
https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M533/K113/533113457.PDF. 2 the slice-of-day (SOD) planning reserve margin (PRM) calibration, is undergoing additional updates and parties will have an opportunity to comment at a later date.5 CalCCA looks forward to reviewing the updated SOD PRM calibration and commenting on the results at that later date.

These comments focus on the study methodology presented at the July 25, 2024, workshop and recommend improvements to that methodology.

The California Public Utilities Commission (Commission) should focus on “[r]etain[ing] the CPE Framework with modifications to address known issues,”6 in this track of the proceeding rather than attempting to “repurpose” or “dismantle” it. The Resource Adequacy (RA) program is in the process of a significant transition with the implementation of the SOD RA program. The Commission should not contemplate one significant change to the RA program while it has yet to complete another. In this track, the Commission should focus on ways to improve the interactions between the CPE and load-serving entities (LSE) by increasing the certainty LSEs have about their own procurement obligations well in advance of their compliance deadlines.

CalCCA offers the following comments to the LOLE Study and parties’ Track 2 Proposals7 aimed at achieving these objectives:
• Revisit changes to the PRM level when the Commission’s tools and approach are stable;
• Align the Commission’s framework with the primary questions of the RA program;
• Maintain an annual PRM until the Commission’s study methodology is sufficient to evaluate monthly or seasonal PRMs;
5 LOLE Study. 6
CPE Report at 54.
7 References to Track 2 Proposals refer to those filed in R.23-10-011 on June 14, 2024. 3 • Incorporate uncertainty of load forecast, based upon observed Integrated Energy Policy Report (IEPR) forecast errors, into the Strategic Energy Risk Valuation Model (SERVM) forecast error parameters;
• Ensure the contribution of storage to reliability is consistently represented; • Evaluate whether the Commission’s choice to stress the system with flat load materially impacts the PRM result;
• Refrain from repurposing or dismantling the local RA CPE at this time; • Do not shift the CPEs’ role to a backstop role at this time; • Reject Western Power Trading Forum’s (WPTF) proposal to shift the CPEs’ role to a backstop role at this time;
• Reject Middle River Power LLC’s (MRP) proposal to direct CPEs to terminate contracts; and
• Reject Pacific Gas and Electric Company’s (PG&E) and Southern California Edison Company’s (SCE) proposals for modifying the self-showing process; • Work with the California Independent System Operator Corporation (CAISO) to determine how best to harmonize local RA requirements with SOD.

II. LOLE RECOMMENDATIONS
A. Revisit Changes to the PRM Level When the Commission’s Tools and Approach are Stable
The Commission is continuing to identify necessary changes to the SOD PRM calibration tool, calling into question the recommended PRM put forth in the LOLE Study. In addition, CalCCA suggests several changes or alternatives in the comments below. It is premature to change the PRM while the tools and approach are being revised and vetted by stakeholders. The RA program is already undergoing a major transition from the peak-hour to SOD framework.

Major changes to the level of the PRM only make sense once the Commission’s tools and approach and this new framework has been implemented, tested, and proven successful. 4 B. Align the Commission’s Framework with the Primary Questions of the RA Program
The Commission’s process for making a PRM recommendation follows the following steps:
1) Identify the baseline set of resources expected to be available in 2026 (Baseline),
2) Evaluate the reliability of the baseline portfolio in SERVM, 3) Calibrates the baseline portfolio to meet the 0.1 LOLE target (Calibrated Baseline),
4) Apply the SOD accreditation rules to the resources in the Calibrated Baseline portfolio,
5) Use the accredited supply to calculate the reserve margin in each hour and month,
6) Finds the amount of additional flat load the Calibrated Baseline portfolio can accommodate before the hour with the lowest reserve margin matches that found in the highly constrained month of September, and 7) Use SERVM to validate that the Calibrated Baseline portfolio is able to meet the demand plus additional flat load in each month with an adequate level of reliability.

The logical connection between this process and the objectives of the Commission’s RA program is not obvious and easy to follow. The Commission’s monthly RA program allocates the forecasted 1-in-2 peak demand to LSEs and then asks LSEs to show contracts with resources that, when accredited based on the SOD rules, meet or exceed their share of the allocated demand and a PRM. The primary question of the RA program is therefore: If LSEs show resources that, using the SOD accreditation rules, meet their share of the demand and PRM, will the resulting system be reliable? The process for setting the PRM and accrediting resources in the SOD framework should be organized and flow from this primary question. 5 C. Maintain a Single Annual PRM Until the Commission’s Study Methodology is Sufficient to Evaluate Monthly or Seasonal PRMs
The Commission’s current process sets a target annual PRM at the lowest level of reserves in the Calibrated Baseline relative to the 1-in-2 peak day demand. The Commission then finds the increase in the flat load that causes the lowest reserves in each month to match the target annual PRM. The Commission uses SERVM to verify that the Calibrated Baseline with the additional flat load still achieves a reliability level of LOLE equal to 0.1.

Missing from this current methodology is as characterization of the variability and uncertainty of the system that would warrant monthly or seasonal variation in the PRM rather than an annual PRM. The Commission should not accept proposals8 for a monthly or seasonal PRM until the Commission’s methodology is revised to evaluate the advantages and feasibility of such a shift.

To consider a monthly or seasonal PRM, the Commission’s methodology would need to include the following elements. It would need to characterize variability in peak demand around the 1-in-2 peak day for each month. Until an unforced capacity accreditation is in use, the Commission’s methodology would also need to evaluate monthly and seasonal differences in supply variability. The methodology would need to consider the economic efficiency of varying PRMs. Finally, the methodology would need to ensure that the generation resources needed to meet each month’s PRMs have sufficient opportunity for planned outages. If the PRM is too high in low-demand months, all resources may need to be shown, eliminating opportunities for maintaining the generation fleet and adversely impacting reliability. 8 American Clean Power-California Track 2 Proposals at 3.

Track 2 Proposals of Vistra Corp at 4-6.
6 CalCCA provides the following analysis to illustrate how the Commission could modify the study methodology to evaluate differences in monthly demand variability that would be the basis for monthly PRMs. CalCCA used the 23 weather years of consumption data from the Commission’s 2023 System Modeling Datasets9
to show how peak day demand varies across
weather years from the 1-in-2 peak day demand used to set RA requirements. Figure 1 shows the distribution of the hourly demand on peak days in each month relative to the 1-in-2 peak day demand in each month. The variation in peak day demand around the 1-in-2 peak demand is largest for April, May, June, September, and October. The variation is distinctly smaller in January, February, March, and July. This is the type of analysis required to suggest that a monthly PRM would differ to account for greater variability of peak demand around the 1-in-2 peak demand in some months compared to others. The Commission would need to use a similar analysis to justify a PRM that varies from month to month rather than a single annual PRM.

Figure 1. Variation in Peak Demand Across Weather Years Relative to 1-in-2 Peak Demand for Each Month
9 Analysis is based on the Commission’s Hourly Consumption Demand (all regions, all weather years, Monday start) for 2026 from the System Reliability Modeling Datasets 2023 at https://files.cpuc.ca.gov/energy/modeling/2023PSP/LoadProfiles_AllRegions_MondayStart.zip. "C
~ 1.2
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0 -" ro
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~ 0.9 "C
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"' ffi 0.8 0
1 2 3 4 5 6 7 8 9 10
Month
11 12
2 4
6 8
10 12
14 16
18 20
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7 D. Incorporate Uncertainty of the Load Forecast, Based on Observed IEPR Forecast Errors, into SERVM Forecast Error Parameters
The Commission identifies a gap between the IEPR forecast used to set the SOD PRM and the IEPR forecast used to set the RA load requirements and asks how best to address this gap. Differences in the IEPR 1-in-2 load forecast and the actual 1-in-2 weather year should be accounted for in reliability assessments and PRM setting. The Commission’s SERVM model includes a load forecast error parameter that can be used to account for non-weather related load forecast errors.10 However, CalCCA has pointed out in previous comments11 that the economic load forecast error used in SERVM is derived from a European Central Bank survey of professional forecasters, rather than California’s experience forecasting the 1-in-2 peak load. The Commission should consider using load forecast errors from historical IEPR forecasts.

E. Ensure the Contribution of Storage to Reliability is Consistently Represented The SOD accreditation of storage in the Commission’s process is a critical piece of setting the PRM to ensure reliable portfolios. The accreditation of storage should be consistent with the capabilities of storage represented in SERVM. The Commission should validate the dispatch of the SOD PRM Tool by comparing the storage dispatch in the tool to the SERVM dispatch on days with loss of load, particularly in the highly constrained month of September.

F. Evaluate Whether the Commission’s Choice to Stress System with Flat Load Materially Impact PRM Results
The Commission’s approach includes a choice to add flat load to each month to bring the reserves shown by the Calibrated Baseline to the annual PRM target level. Adjusting portfolios 10 California Public Utilities Commission. Proposed Inputs & Assumptions: SERVM 2024 Data Updates in Support of Resource Adequacy (RA) and Integrated Resource Planning (IRP) at 7:
https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M527/K361/527361341.PDF. 11 California Community Choice Association’s Informal Comments on the Draft Inputs and Assumptions (2023 I&A) at 4: https://cal-cca.org/wp-content/uploads/2023/07/Final-Informal-Commentson-Draft-2023-IA-Document-06-21-23.pdf. 8 by adding perfect capacity resources or flat load (i.e., negative generators with zero forced outage rates) are used as proxies in reliability studies by other jurisdictions, including the Midwest Independent System Operator.
12 However, given the PRM is intended to capture
resource and demand volatility, simply adding flat loads may not be sufficient to assess actual resource needs in a specific month. Choosing these perfect capacity or flat loads may have material impacts in the Commission’s unique SOD framework relative to other options. For example, adding flat load disproportionally reduces the availability of excess resources to charge storage in the off-peak hours. Alternatives such as scaling load by the same percentage in all hours or scaling the entire baseline portfolio should be evaluated by the Commission to demonstrate that PRM results are insensitive to the choice of approach.

III. CPE RECOMMENDATIONS
A. Refrain from Repurposing or Dismantling the Local RA CPE at this Time Several parties advance proposals to repurpose the CPE framework to procure and plan for gas retirements or dismantle the CPE framework. The Commission should not repurpose the CPE within Track 2. Repurposing the CPE in Track 2 to procure and plan for gas retirements would rush to a solution that does not holistically consider the need. Planning for local gas retirements requires an assessment of generation and transmission to determine the optimal path forward for reducing reliance on natural gas; either by developing new clean resources in the local area or developing transmission to reduce the local area constraints.

While PG&E supports establishing a centralized planning and procurement process to reduce reliance on natural gas, PG&E rightly notes, “[b]ecause local capacity areas are 12 Midcontinent Independent System Operator. Planning Year 2023-2024 Loss of Load Expectation Study Report at 33: https://cdn.misoenergy.org/PY%202023- 2024%20LOLE%20Study%20Report626798.pdf.
9 transmission-constrained, it is important that [a centralized planning and procurement] process and structure consider both transmission-based and supply-based solutions; however, these trade-offs cannot be solely captured and determined within the RA proceeding and the development of a process will also require coordination with the IRP proceeding and CAISO’s TPP...” 13 Without coordination with the IRP and TPP processes first, the Commission cannot determine that centralized procurement through the local RA CPE is the most efficient, cost-effective way to reduce reliance on natural gas in local areas.

As California Energy Storage Alliance (CESA) states, there is a risk that “... repurposing the CPE framework would result in retention of existing natural gas plants, rather than holistically capturing the procurement that is needed to meet reliability needs and California’s clean energy goals, as would be done through the IRP process.”14 Rather than repurposing the CPE, the Commission should develop a process within the IRP proceeding that evaluates the generation and transmission solutions needed to reduce reliance on local gas-fired resources.

The Commission should also refrain from contemplating dismantling the CPE at this time. The Commission is currently in the process of transitioning from the peak-hour RA program to the hourly SOD RA program. The Commission should not contemplate a new significant change to the RA program until the SOD program has been implemented, tested, and proven successful. This is especially true because the local RA CPE itself has only had local RA requirements for the last two years, and the Commission and parties are only now conducting a comprehensive review of the effectiveness of the local RA CPE framework.

The constant shifting of LSE compliance frameworks, rules, and obligations makes it difficult for the market to adjust and settle into changes as they occur. While broader structural 13 PG&E Track 2 Proposals at 9-11.
14 CESA Track 2 Proposals at 4.
10 changes to the CPE framework may be beneficial or necessary, developing and adopting them now could do more harm than good, given the state of the RA market today and the transitions already in progress. Retaining the CPE framework with modifications to address known issues will allow RA market participants to focus on adjusting to changes already in progress. Once the RA market calms and the Commission has fully transitioned to its permanent system RA framework, the Commission can consider broader structural changes to the CPE framework.

B. Do Not Shift the CPEs’ Role to a Backstop Role at this Time WPTF proposes that “the Commission retain the CPE framework while refocusing CPE procurement on local resources that are needed to meet local reliability requirements and have not been contracted by LSEs to meet system RA requirements. In other words, the CPEs would be limited to a backstop procurement role aimed at addressing any residual local capacity needs.”15 WPTF’s proposal “would depend in part on the adoption of multi-year forward procurement requirements for LSEs.”16 Given that multi-year forward RA requirements are not in the scope of Track 2, WPTF recommends the Commission defer consideration of proposals to repurpose or dismantle the CPE in parallel with the Reliable and Clean Power Procurement Program (RCPPP).

The Commission should not consider modifying the CPE’s role to a backstop role at this time. CalCCA agrees with WPTF that proposals to modify the CPE’s role should be considered in alignment with the RCPPP. This will ensure a comprehensive and coordinated approach to ensuring the retention of existing resources needed for reliability. In addition, RA prices are 15 WPTF Track 2 Proposals at 10.
16 Id. at 11.
11 currently at all-time highs.17 While multi-year RA may be one way to ensure the retention of existing resources, rushing to adopt multi-year forward RA requirements for LSEs now will ensure high-price contracts are locked in for multiple years forward, exacerbating the ongoing affordability crisis facing the state’s customers. For these reasons, the Commission should defer consideration of proposals contingent on multi-year system RA at this time.

C. Reject MRP’s Proposal to Direct CPEs to Terminate Contracts MRP proposes the Commission “authorize and require the CPEs to terminate CPE capacity contracts to allow that capacity to be transferred to another LSE when that LSE elects to procure directly with the resource owner for a long-term contract, identified as five (5) years or greater, and such contract has a delivery period that is overlapping with the existing CPE contract.” 18 The purchasing LSE would then have an obligation to self-show that capacity for the duration of the former contract with the CPE.

The Commission should not adopt MRP’s proposal. MRP acknowledges “[t]his conversion from CPE-contracted capacity to self-shown capacity would affect other LSEs serving load in the same TAC area. Such LSEs would receive fewer CAM credits during the same period.”19 While MRP suggests giving LSEs notice of transfers by June 30 prior to the compliance year would give LSEs “some level of volumetric certainty” of their CPE allocations, MRP’s proposal would exacerbate existing challenges LSEs face with predicting their allocations. As a result of this proposal, the allocations that LSEs expect to receive after procurement for the CPEs’ two-year ahead and three-year ahead requirements could decrease or 17 California’s Constrained Resource Adequacy Market: Ratepayers Left Standing in a Game of Musical Chairs (updated Jan. 16, 2024) at 9-11: https://cal-cca.org/wp-content/uploads/2024/02/CalCCA-Stack-Analysis-2023-2026-updated-01_16_24-.pdf. 18 MRP Track 2 Proposals at 13. 19 Id. at 16.
12 be taken away entirely, significantly impacting LSEs' ability to plan for their own system and flexible RA requirements.

This proposal will not result in reliability or affordability benefits to justify such added uncertainty. Transferring CPE procurement does not increase the amount of capacity under contract for the Commission’s RA program. It simply transfers the costs and benefits LSEs would already pay for collectively to an individual LSE, or LSEs. The MRP proposal would allow generators to abandon relatively low-priced contracts with the CPE, who can defer procurement to backstop if prices are too high, for higher ones with LSEs, who cannot defer their procurement due to high costs. For these reasons, the Commission should decline to require the CPE to terminate contracts for resources individual LSEs want to procure.

D. Reject PG&E and SCE’s Proposals for Modifying the Self-Showing Process SCE and PG&E propose changes to the process LSEs use to voluntarily “self-show” local capacity they have under contract to the CPEs. The existing self-showing process allows LSEs to voluntarily self-show capacity to the CPE. In some cases, LSEs will receive compensation for self-showings via the local capacity reduction compensation mechanism (LCR-RCM). These cases are limited, however, as the LCR-RCM only applies to preferred resources and energy storage and only results in payment when the local RA premium is greater than zero.20 LSEs take on risks and lose flexibility in their portfolio by self-showing which likely prevents LSEs from doing so, especially given the limited incentives to self-show.

SCE proposes that the Commission “require LSEs who plan to include system resources located in a local area toward their system RA requirements to self-show that resource earlier 20 https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/resource-adequacy-homepage/resource-adequacy-compliance-materials/lcr-rcm-2024.pdf. 13 than the October year-ahead system filings.”21 SCE suggests that its proposal would “reduce the amount of local RA the CPE is required to procure, which would reduce RA costs included in customers’ rates.”22 The Commission should not adopt SCE’s proposal. “Forcing” LSEs to self-show ignores the inherent risks associated with self-showing. SCE asks that the Commission force LSEs to make decisions about their portfolios prior to the current deadlines. As CalCCA has previously pointed out, self-showing is not risk free. Those that self-show reduce portfolio flexibility in selling portions of their portfolio or potentially taking planned resource outages.

Effectively, SCE is asking that LSEs perform their procurement and self-show, turning the CPE into a backstop entity for local rather than have the primary responsibility for local area procurement. CalCCA’s modified CPE timeline proposal is a better way to manage local RA costs because, rather than requiring LSEs to take on risks involuntarily, it would allow LSEs to do their procurement with an understanding of the allocations it will receive from the CPE. This will reduce the need for LSEs to over-procure to manage the uncertainty associated with allocations that come after the LSE does its own procurement.

PG&E proposes to eliminate the self-showing process in favor of a process for “CPEs to collect information directly from Energy Division regarding local RA capacity that is already under contract with LSEs.”23 The information Energy Division would collect from LSEs would include: resource ID, local area, contract start and end date, technology type, and contracted MW. The Commission should not adopt PG&E’s proposal. While the proposal intends to give the CPE more information to use in its procurement decision-making processes, it is unclear what purpose having this information would serve. If the information is intended to indicate 21 SCE Track 2 Proposals at 3.
22 Id. 23 PG&E Track 2 Proposals at 6.
14 which resources may be unavailable for CPE procurement, the CPE will know such information after those resources are not offered into its solicitations. Additionally, it is not possible to use this information to understand which resources may be offered into its solicitations or shown for system RA. If a resource is not under contract by an LSE, it does not imply that it will be available for CPE procurement. It could be under contract by a non-Commission jurisdictional LSE or out-of-state entity. If a resource is under contract by an LSE, it does not imply that it will be shown for system RA. It may be held for substitution or sold to another LSE. Finally, the LSE may themselves offer it to the CPE as a local RA sale. If PG&E knows that the resource is under contract to an LSE, they would likely forego procuring the resource for local RA, defeating the original design which allows any entity to offer to sell local RA to the CPE with equal opportunity of being procured.

Given the usefulness of the CPE having this information is questionable, the Commission should refrain from adopting this proposal to avoid the adverse impacts it could have on LSE procurement activities. PG&E’s proposal would provide one procuring entity (the CPE) with more information than other procuring entities (LSEs). In addition, it is not clear that the existing firewalls in place to separate the IOUs’ CPE functions and LSE functions are sufficient to ensure the IOUs do not have a competitive advantage over LSEs. CalCCA’s proposal to revise the CPE timeline would avoid these concerns and result in more efficient local and system RA procurement because it would reinstate a sequential procurement process in which LSEs know their CPE allocations prior to its year-ahead system RA procurement processes.

For these reasons, the Commission should forego the recommendations of SCE and PG&E and instead adopt CalCCA’s proposal to modify the timeline to allow the CPE to complete its procurement after its two-year ahead procurement process. This proposal would --
15 result in more efficient local and system RA procurement processes and contain RA costs by providing LSEs certainty around their CPE allocations and thus preventing the need to over procure to mitigate the risk of unknown CPE allocations.

E. Work with the CAISO to Determine How Best to Harmonize Local RA Requirements with SOD
SCE proposes to “shift local RA requirement setting from the Effective Load Carrying Capacity-based Net Qualifying Capacities to incorporating peak hour values of the month from energy sufficiency profiles…” to “harmonize the methodology for showings for the CPE local RA and system [SOD] frameworks.”24 CalCCA supports additional consideration of the right ways to harmonize the local and system RA programs. Given the differences in requirement setting for local RA and system RA, the Commission should work with CAISO to determine how best way to do so.

Unlike system RA requirements, which are primarily driven by 1-in-2 load, local RA requirements are driven by transmission contingencies under 1-in-10 load. Thus, it is likely not necessary to develop hourly local RA requirements like those adopted for system RA, but it may be necessary to revise the resource values used for local RA to align with those used for system RA. The CAISO should inform the Commission of its assumptions used for variable resources and storage in its local capacity technical study and inform the right way to harmonize local and system RA.
24 SCE Track 2 Proposals at 3.
16 IV. CONCLUSION
For all the foregoing reasons, CalCCA respectfully requests consideration of the recommendations herein and looks forward to an ongoing dialogue with the Commission and stakeholders.

Respectfully submitted,
Evelyn Kahl,
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
August 9, 2024
t
4 Contact
Shawn-Dai Linderman ([email protected])

1. Please provide a summary of your organization’s general comments on the Issue Paper & Straw Proposal (IPSP) and the stakeholder meeting.

The California Community Choice Association (CalCCA) appreciates the opportunity to comment on the California Independent System Operator’s (CAISO) storage bid cost recovery (BCR) and default energy bids (DEB) enhancements workshop. CalCCA agrees with the CAISO that the BCR framework should not disincentivize consideration of real-time conditions and should not present opportunities for pursuing unwarranted revenue. The pace the CAISO intends to conduct this initiative, however, does not allow the time necessary to develop a robust solution to the complex problem of accurately determining when BCR is warranted or unwarranted.

The CAISO proposes to reclassify energy associated with state of charge (SOC) constraints during the binding interval as non-optimal due to physical limitations A blunt mechanism to addressing some portion of BCR payments being unwarranted, like the CAISO’s proposal, does not account for the fact that legitimate cost-based bids into the real-time market may result in the dispatch of storage in a manner that results in buy-backs or sell-backs and accruing BCR.

As discussed in CalCCA’s July 18, 2024, comments,[1] excluding storage from BCR in most instances is too blunt of a mechanism to be the permanent solution but the pace of this initiative may be too quick to develop something more robust. The CAISO’s Track 1 proposal should be a temporary solution only. The CAISO must commit to beginning an initiative immediately following Track 1 to develop a more comprehensive solution to unwarranted BCR payments that considers (1) the drivers of BCR payments (e.g., resource operator action to trigger BCR payments or CAISO market dispatch), and (2) necessary enhancements to the storage market model more broadly.
[1] https://stakeholdercenter.caiso.com/Comments/AllComments/f7f6fb35-66cd-4279-821d-8711799e4468#org-37ce3de3-fe23-4352-b48c-28724ba3e358.

2. Please provide your organization’s comments regarding the framing, scope, and schedule of the initiative as stated in the IPSP (Sections 1 and 2).

See response in Section 1. Again, the timing for Track 1 is likely untenable to come to an effective resolution that addresses unwarranted storage BCR. It does not allow sufficient time for the CAISO to analyze the driver of BCR payments, whether those payments are warranted or unwarranted, and the magnitude of such payments.

The CAISO should view any measures adopted in Track 1 as temporary until the CAISO and stakeholders can develop a more robust solution promptly following the conclusion of Track 1.

3. Please provide your organization’s comments regarding the issue of unwarranted storage BCR and the examples included in the IPSP (Sections 3.1 and 3.1.1).

See response in Section 1.

4. Please provide your organization’s comments regarding the issue of BCR provisions for energy storage in co-located configurations as stated in the IPSP (Section 3.2).

California Community Choice Association SUBMITTED 08/08/2024, 02:07 PM 8/27/24, 12:51 PM California ISO - All comments
https://stakeholdercenter.caiso.com/Comments/AllComments/0FD91812-9653-4034-853C-D7F32A932919#org-5b429ff9-474f-44e7-9566-04d8e9c368… 1/2 CalCCA has no comments at this time.

5. Please provide your organization’s comments regarding the estimation of opportunity costs within the storage Default Energy Bid (DEB) as stated in the IPSP (Section 3.3).

CalCCA has no comments at this time.

6. Please provide your organization’s comments regarding the proposal to reclassify energy associated with SOC constraints during the binding interval as non-optimal due to physical limitations (Section 4).

See response in Section 1.

7. Please provide your organization’s comments regarding the proposed governance classification as stated in the IPSP (Section 5).

CalCCA has no comments at this time.

8. Please provide any additional comments, feedback, or examples regarding the IPSP and the stakeholder meeting. You may upload examples or data using the “Attachments” field below.

CalCCA has no additional comments at this time.
8/27/24, 12:51 PM California ISO - All comments
https://stakeholdercenter.caiso.com/Comments/AllComments/0FD91812-9653-4034-853C-D7F32A932919#org-5b429ff9-474f-44e7-9566-04d8e9c368… 2/2 Contact
Shawn-Dai Linderman ([email protected])

1. Please provide a summary of your organization's overall comments on the Resource Adequacy Modeling and Program Design (RAMPD) Revised Discussion Paper and Final Recommendation Plan posted on July 26, 2024.

The California Community Choice Association (CalCCA) appreciates the opportunity to comment on the California Independent System Operator’s (CAISO) RAMPD Revised Discussion Paper and Final Recommendation Plan. CalCCA generally supports the Revised Discussion Paper and Final Recommendation Plan with respect to the three tracks moving forward to policy development and the problem statements for those tracks. Its primary concerns with the CAISO’s updated path forward for tracks 2 and 3 are:

The CAISO should not shift the resource adequacy (RA) program from monthly showings to annual showings.

As described in CalCCA’s May 27, 2024, comments,[1] the CAISO should not shift the RA showing granularity from monthly to yearly because there is less certainty of the availability of certain resources (primarily hydro and imports) in the year-ahead time frame than in the month-ahead time frame.

The CAISO should not include a planned outage buffer in the PRM.

As described in CalCCA’s May 27, 2024, comments,[2] the CAISO should not consider a planned outage buffer as doing so would shift the burden of generator outages from the party that can control outages (the generator) to a party that cannot (the load-serving entity (LSE)).

The CAISO should not link the capacity procurement mechanism (CPM) Soft Offer Cap (SOC) to bi-lateral market prices.

As described in CalCCA’s July 2, 2024, comments,[3] the lack of Clean System Power (CSP) offers is not a function of the way the CAISO’s current backstop processes are designed but rather a function of the current lack of capacity that has RA market prices unprecedentedly high. This does not signal a need to change the current CPM SOC. The process for defining the SOC works as intended, covering going-forward fixed costs of the marginal resources on the system and mitigating market power while allowing a generator that can demonstrate higher costs to recover those costs. It is not intended to be competitive with bi-lateral market prices, which currently reflect market scarcity rather than resources’ costs.

CalCCA supports exploring the other elements of the CAISO’s updated path forward for tracks 1, 2, and 3 and looks forward to continuing to engage in the policy development phase of this initiative. [1] https://stakeholdercenter.caiso.com/Comments/AllComments/a79881e1-374a-4d13-aa17- cbbf7e631b3a#org-6b240e6d-295e-4f19-9bf2-280896d7b4a4.
[2] Id.
[3] https://stakeholdercenter.caiso.com/Comments/AllComments/10d5fec5-8032-43e4-aa30- 067535d504e8#org-52666ab8-09fa-4ee9-8b71-00cbb97ea0b9.

California Community Choice Association SUBMITTED 08/12/2024, 03:04 PM 9/3/24, 10:39 AM California ISO - All comments
https://stakeholdercenter.caiso.com/Comments/AllComments/0A165B0F-66FA-491B-8D7A-CD2DAE5AC420#org-08d4e33d-0b4f-46ad-8699-fa867a2… 1/1 •
0 • 0
•
0 STATE OF CALIFORNIA GAVIN NEWSOM, Governor

PUBLIC UTILITIES COMMISSION
SAN FRANCISCO, CA 94102
505 VAN NESS AVENUE
-3298
August 21, 2024
Advice Letter 79-E/E-A
San Rafael, CA
1125 Tamalpais Ave
Marin Clean Energy
Policy Analyst
Amulya Yerrapotu
94901
E-mail: [email protected]
SUBJECT:

Disadvantaged Communities Green Tariff Program
2025 Budget Request and Marketing, Education and Outreach Plan for the Dear Amulya Yerrapotu:

Marin Clean Energy Advice Letter 79-E/E-A is effective as of August 7, 2024.

Sincerely,
Deputy Executive Director for Energy and Climate Policy Leuwam Tesfai
/
California Public Utilities Commission
Director, Energy Division f -t

UNITED STATES OF AMERICA

BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION
California Independent System Operator
Corporation ) Docket No. ER24-2671-000
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S COMMENTS ON
THE CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION’S TARIFF AMENDMENT TO IMPLEMENT TRACK 2 OF INTERCONNECTION PROCESS ENHANCEMENT 2023 INITIATIVE
Pursuant to Rule 211 of the Federal Energy Regulatory Commission’s (Commission) Rules of Practice and Procedure,1
18 C.F.R. Section 385.212 (2023), the
California Community Choice Association2 (CalCCA) submits these comments to the California Independent System Operator Corporation’s (CAISO) Tariff Amendment to Implement Track 2 of Interconnection Process Enhancements 2023 Initiative3 (Tariff Amendment), dated August 1, 2024. The Tariff Amendment seeks to implement reforms essential for the CAISO to adapt to the dramatically increased levels of requests to interconnect to the CAISO-controlled grid.
1 Federal Energy Regulatory Commission’s Rules of Practice and Procedure, Part 385. 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 California Independent System Operator Corporation’s Tariff Amendment to Implement Track 2 of Interconnection Process Enhancements 2023 Initiative, ER24-2671-00 (Aug. 1, 2024). 2 I. INTRODUCTION
CalCCA is a trade association representing the interests of 24 community choice aggregators (CCA) in California. CalCCA’s membership serves over 14 million customers in over 200 cities and counties throughout the state, representing roughly one-third of the CAISO load in California. As load-serving entities (LSE) actively procure new electric generating resources to serve California customers, California CCAs have a direct interest in ensuring an efficient and effective interconnection process that supports the accelerated pace of clean energy resource development. CalCCA requests the Commission accept the CAISO’s Tariff Amendment, which makes meaningful improvements to the CAISO’s ability to support the pace of interconnection necessary to achieve California’s policy and reliability needs.

II. COMMENTS
CalCCA respectfully asks that the Commission accept the CAISO’s Tariff Amendment. The Tariff Amendment comes at a critical point when procurement activities have expanded at a rapid pace to maintain reliability targets while meeting California’s clean energy policies, like Senate Bill (SB) 100 (De León).4 CalCCA estimates that to reach SB 100 targets on schedule, California will need over 6,000 megawatts of new resource interconnection per year from 2024 to 2045, an increase in the annual net growth rate by roughly 400 percent relative to the net growth rate from 2001 to 2023.
5 While the entire industry is moving as quickly as possible to bring new 4 SB 100 requiring renewable energy and zero-carbon resources supply 100 percent of electric retail sales to end-use customers by 2045.
5 2001-2022 Electric Generation Capacity and Energy, California ISO 2023Year in Review less 2023 retirements list, and SB100 Joint Agency Report (assumes straight line growth between 2024 and 2045).
3 clean resources online, policies and processes need to evolve to accommodate the unprecedented pace of procurement that will continue as California progresses toward its SB 100 goals.

The Tariff Amendment advances much-needed transformations to the interconnection cluster study and queue management processes while maintaining open access to the transmission system. It intends to prioritize interconnection requests by ranking requests within available transmission zones based on indicators of readiness; commercial interests, project viability, and system needs. It also recognizes the importance LSE interest will play when narrowing down the pool of interconnection study requests. LSEs, as procuring entities, conduct long-term planning activities in their individual integrated resource plans, where they start to identify the technologies, locations, and magnitudes of projects they will pursue to support the communities they serve. LSEs must procure a variety of technologies to achieve both reliability and greenhouse gas reductions in a cost-effective manner that meets their customers’ needs, and in the case of some LSEs like CCAs, complies with their governing boards' mandates. This procurement activity is factored into the California Public Utilities Commission’s preferred system plan, which then informs the CAISO’s transmission planning process.

Without an LSE interest-scoring criterion, the CAISO would risk having an interconnection queue that is not aligned with resource and transmission planning processes taking place in these forums. Given that reliability depends critically on having the right mix of resources on the grid, this alignment with planning is fundamentally 4 important to CAISO’s operations. CalCCA agrees with the CAISO that the commercial interest category is:
...a critical piece of the tariff reforms proposed in this filing. Given the LSEs’ essential role in resource procurement under California state law and the Commission-approved resource adequacy provisions of the CAISO tariff, LSE interest is a key indicator of commercial interest and the ultimate viability of a generation project seeking interconnection. Awarding points for commercial interest will allow the CAISO to remove speculative projects not likely to be viable earlier in the interconnection process and provide a useful metric in determining whether a project is ready for study.6 CalCCA supports the CAISO’s objective of a robust, fair, and transparent point allocation process, and appreciates the CAISO’s Track 2 Final Addendum which (1) provides requirements for opting into the allocation process, publicly posting selection criteria, and acting in a non-discriminatory manner, and (2) strongly encourages incorporating best practices into the LSE allocation processes.7 CCAs are committed to making the LSE point allocation process as transparent and fair as possible. CCAs intending to participate in the allocation process are committed to taking the CAISO’s encouragement to “conduct public requests for information, requests for offers, or some other functionally equivalent process to ensure fairness, transparency, and competition in the LSE allocation process.”8 They are also open to continuing to work with the CAISO and developers to improve the LSE point allocation process as LSEs, the CAISO, and developers gain experience with the new interconnection study process. 6 Tariff Amendment at 49.
7 Id. at 49-50.
8 Id. at 50: https://statics.teams.cdn.office.net/evergreen-assets/settings/window-mode/window-mode-coachmark.svg. 5 III. CONCLUSION
CalCCA respectfully requests that the Commission accept the CAISO’s Tariff Amendment.

Respectfully submitted,
Evelyn Kahl,
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
August 22, 2024
t

CERTIFICATE OF SERVICE
I, Shawn-Dai Linderman, hereby certify that I have this day served a true copy of CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S COMMENTS ON
THE CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION’S TARIFF AMENDMENT TO IMPLEMENT TRACK 2 OF INTERCONNECTION PROCESS ENHANCEMENT 2023 INITIATIVE by electronic mail to each party of record designated on the official service list in the above-captioned proceeding.

Executed on August 22, 2024, at Martinez, California.
/s/ Shawn-Dai Linderman
Shawn-Dai Linderman

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
1121 L Street, Suite 400
Sacramento, CA 95814
(510) 980-9459
[email protected]
California Community Choice Association
1121 L Street, Suite #400, Sacramento, CA 95814
[email protected] | cal-cca.org
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S
INFORMAL COMMENTS ON THE 2025 RESOURCE

ADEQUACY AND SLICE OF DAY GUIDE
I. INTRODUCTION
The California Community Choice Association1 (CalCCA) appreciates the opportunity to comment on the 2025 Resource Adequacy and Slice of Day Guide (2025 RA Guide), issued July 29, 2024, the Slice-of-Day (SOD) templates, and other matters related to SOD implementation.

CalCCA offers the following recommendations in the comments below:
• The California Public Utilities Commission (Commission) must correct validation test errors;
• The Commission must clarify the process for adding resources to the master resource database (MRD) to count Resource Adequacy (RA) expected to come online for month-ahead filings; and
• The Commission must issue its draft and final MRDs in a timely manner.

II. COMMENTS ON THE SOD TEMPLATES
A. The Commission Must Correct Validation Test Errors
The latest version of the SOD template continues to contain issues with the flexible capacity validation test and storage excess capacity validation test. There appears to be a 1 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.

CalCCA Informal Comments on RA Guide

Page 2 ends

August 22, 2024
California Community Choice Association
1121 L Street, Suite #400, Sacramento, CA 95814
[email protected] | cal-cca.org
discrepancy between the SOD template and the template filing guide, and the template is providing incorrect validation results on the “Validation Overview” tab. For example, the equation for the flexible capacity validation test on page 23 of the template user guide clearly states that a load-serving entity’s (LSE) total countable flexible capacity must be greater than the sum of its category requirements. The validation test in the template only nets an LSE’s total countable flexible capacity against its flexible capacity category 2 and 3 requirements, not all three flexible capacity category requirements. As a result, the template reports that an LSE has passed the flexible capacity validation test even if their total countable flexible capacity is less than their total flexible requirement.

The storage excess capacity validation test faces similar issues. The template appears to undercount the total excess capacity needed to charge shown storage resources, resulting in the potential to falsely pass the validation test. These issues create significant uncertainty regarding how these validation tests will be measured for the 2025 year-ahead filing. While the “Profile Optimization” tab could be a valuable tool for LSEs to use to optimize the use of their storage resources in their SOD showings, LSEs continue to have issues using the profile optimization tab, limiting its use. In addition, LSEs would get the most value out of the optimizer if it were to use storage to minimize open positions, and Energy Division confirmed during the SOD Office Hours on August 16, 2024, that is not the goal of the Profile Optimization tab. Therefore, LSEs are left to manually input storage into the tool using the custom profiles tab to optimize their portfolios. This makes it especially critical that the Commission should resolve the storage CalCCA Informal Comments on RA Guide

Page 3 ends

August 22, 2024
California Community Choice Association
1121 L Street, Suite #400, Sacramento, CA 95814
[email protected] | cal-cca.org
excess capacity validation test, in addition to the flexible capacity validation test, as soon as possible so that LSEs can validate 2025 positions.

III. COMMENTS ON THE MRD
A. The Commission Must Clarify the Process for Adding New Resources to the MRD to Count RA Expected to Come Online for Month-Ahead Filings The Commission allows LSEs to show resources under construction at the time of the year-ahead filing to meet year-ahead RA obligations. The resource must then demonstrate that it is operational prior to the month-ahead filing for the LSE to use it for its month-ahead obligation.2 It also allows resources that reach commercial operation dates between the month-ahead RA showings and the start of the RA month to count as cure capacity in the summer months.3
The 2025 RA Guide documents the process for the latter, 4 but not the former.

To count new resources that reach commercial operation between the year-ahead and month-ahead RA processes on month-ahead RA showings, the California Independent System Operator Corporation (CAISO) requires resources to request to be moved from the “under construction” tab on the Net Qualifying Capacity (NQC) list to the main tab. The CAISO only allows resources on the main tab to count towards the monthly RA showings. The CAISO updates its NQC list monthly to reflect these new resources that come online each month on the main tab.
5 The 2025 RA Guide does not include detailed instructions on how to add these 2 CAISO Reliability Requirements BPM at 82. 3
D.24-06-004, Decision Adopting Local Capacity Obligations for 2025-2027, Flexible Capacity Obligations for 2025, and Program Refinements, R.23-10-011 (June 26, 2024), at 32-34:
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M534/K619/534619523.PDF. 4 2025 RA Guide at 4-5. 5
CAISO Reliability Requirements BPM at 82.

CalCCA Informal Comments on RA Guide

Page 4 ends

August 22, 2024
California Community Choice Association
1121 L Street, Suite #400, Sacramento, CA 95814
[email protected] | cal-cca.org
resources to the MRD to allow RA resources that come online before the month-ahead filing to count towards an LSE’s month-ahead RA requirements. Instead, the 2025 RA Guide states the MRD, “will be updated annually for deliverability and [NQC] updates.”6 The Commission should update the MRD to include the process it will use for counting new resources that come online prior to a month-ahead filing. If that process is for LSEs to add resources into the MRD tab in the showing tool, the Commission should provide specific instructions for how to enter resources so that they will flow properly through the showing tool.

B. The Commission Must Issue its Draft and Final MRDs in a Timely Manner CalCCA appreciates the Commission’s ongoing communication with stakeholders about changes to the MRD that will impact resources’ final MRD values. Because the MRD is the official database of RA-eligible resources eligible and their key attributes and resources must be “fully represented” in the MRD to be used in a SOD RA showing, 7 it is imperative the
Commission publish the draft and final MRDs in a timely manner. CalCCA urges the Commission to expeditiously publish the draft and final MRDs so that they are publicly available no later than their successor documents, the NQC lists, have been made publicly available. This will allow LSEs to validate their showings using final data and make any necessary adjustments resulting from that validation.
6 2025 RA Guide at 21. 7
2025 RA Guide at 20.

CalCCA Informal Comments on RA Guide

Page 5 ends

August 22, 2024
California Community Choice Association
1121 L Street, Suite #400, Sacramento, CA 95814
[email protected] | cal-cca.org
IV. CONCLUSION
CalCCA appreciates the opportunity to comment on the 2025 RA Guide and urges the Commission to consider the recommendations herein.

Date: August 22, 2024
(Original signed by)
Eric Little
Director of Regulatory Affairs
California Community Choice Association
(510) 906-0182 | [email protected]

BEFORE THE PUBLIC UTILITIES COMMISSION

R.23-10-011
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY
COMMENTS ON ADMINISTRATIVE LAW JUDGE’S RULING
MODIFYING TRACK 2 SCHEDULE
Evelyn Kahl,
General Counsel and Director of Policy
Lauren Carr,
Senior Market Policy Analyst
Eric Little,
Director of Regulatory Affairs
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]
August 23, 2024
FILED
08/23/24
04:59 PM
R2310011
i

TABLE OF CONTENTS
I. INTRODUCTION ...............................................................................................................1 II. LOLE STUDY REPLY COMMENTS ................................................................................3 A. CalCCA Agrees with Stakeholders Who Suggest More Time and a Structured Process for Setting the PRM ..................................................................3 B. CalCCA Supports the RA Program’s Focus on Reliability, Though Economic Efficiency and Affordability Should be Considered in Setting PRMs ...........................................................................................................4 C. CalCCA Agrees with Stakeholders Who Request Further Clarification and Analysis of the Inputs and Assumptions Used in SERVM Modeling ..................................................................................................................5 D. CalCCA Supports Consistency Between Data Used in SERVM Modeling, SOD PRM Translation, and SOD Accreditation ....................................7 E. CalCCA Disputes Microsoft’s Recommendation that Only the LOLE Study be Used in Setting the PRM ..........................................................................8 F. CalCCA Encourages the Development of a Methodology to Determine Monthly or Seasonal PRMs ...................................................................................10 III. LOCAL RA CPE REPLY COMMENTS ..........................................................................12 A. The Commission Should Reject PG&E’s Proposal to Provide the Local RA CPEs with LSE Procurement Information in Advance of Its Solicitations and SCE’s Modification to the Proposal ...........................................12 B. The Commission Should Dismiss Parties’ Misguided Concerns about the CalCCA CPE Timeline Proposal .....................................................................13 C. CalCCA Agrees with Parties that the Long-Term Local Area Resource Transition is Best Addressed in the IRP Proceeding .............................................17 D. AReM Should Clarify How the CAISO Would Allocate Local CPM Costs .......................................................................................................................19 IV. CONCLUSION ..................................................................................................................19

APPENDIX
ii

SUMMARY OF REPLY COMMENTS
Loss-of-Load Expectation (LOLE) Study Reply Comments
• The California Community Choice Association (CalCCA) agrees with stakeholders who suggest more time and a structured process for setting the planning reserve margin (PRM); • CalCCA supports the resource adequacy (RA) program’s focus on reliability, though economic efficiency and affordability should be considered in setting PRMs; • CalCCA agrees with stakeholders who request further clarification and analysis of the inputs and assumptions used in Strategic Energy Risk Valuation Model (SERVM) modeling; • CalCCA supports consistency between data used in SERVM modeling, slice-of-day (SOD) PRM translation, and SOD accreditation;
• CalCCA disputes Microsoft Corporation’s (Microsoft) recommendation that only the LOLE study be used in setting the PRM; and
• CalCCA encourages the development of a methodology to determine monthly or seasonal PRMs.

Local RA Central Procurement Entity (CPE) Reply Comments • The California Public Utilities Commission (Commission) should reject Pacific Gas and Electric Company’s (PG&E) proposal to provide the local RA CPEs with load serving entity procurement information in advance of its solicitations and Southern California Edison Company’s (SCE) modification to the proposal;
• The Commission should dismiss parties’ misguided concerns about the CalCCA CPE timeline proposal;
• CalCCA agrees with parties that the long-term local area resource transition is best addressed in the Integrated Resource Planning (IRP) proceeding; and • The Alliance for Retail Energy Markets (AReM) should clarify how the California Independent System Operator (CAISO) would allocate local capacity procurement mechanism costs.

BEFORE THE PUBLIC UTILITIES COMMISSION

R.23-10-011
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY
COMMENTS ON ADMINISTRATIVE LAW JUDGE’S RULING
MODIFYING TRACK 2 SCHEDULE
California Community Choice Association1 (CalCCA) submits these Reply Comments pursuant to the Administrative Law Judge’s Ruling Modifying Track 2 Schedule 2 (Ruling), dated June 26, 2024. The Ruling seeks comments on all proposals filed.

I. INTRODUCTION
CalCCA appreciates the opportunity to reply to parties’ opening comments3 on Track 2 proposals related to the Commission’s LOLE study and the local RA CPE. Parties’ opening comments on the LOLE study signal the need to take more time to further evaluate the study methodology before finalizing the PRMs for 2026 and 2027. Accurate inputs and assumptions and a robust study methodology are critical to setting the PRM to meet a 1-in-10 reliability 1 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.
2 Administrative Law Judge’s Ruling Modifying Track 2 Schedule, Rulemaking (R.) 23-10-011:
https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M534/K332/534332050.PDF. 3 References to opening comments refer to those filed on August 9, 2024, in R.23-10-011. 2 standard. The Commission and parties should have confidence that the results will produce a 1-in-10 reliability standard, as setting the PRM too low elevates reliability risks, and setting the PRM too high jeopardizes ratepayer affordability. CalCCA looks forward to additional discussion with the Commission and parties to ensure the LOLE study and resulting PRM threads that needle.

Many parties’ opening comments on the local RA CPE directionally support modifications to the existing local RA CPE framework rather than sweeping reforms to its purpose or existence. Parties disagree, however, on how to reform the existing framework. The Commission should prioritize proposals that retain the existing CPE framework, including the ability for load-serving entities (LSE) to sell to the CPE, self-show to the CPE for compensation, and provide LSEs more certainty about the allocations they will receive from the CPE.

In summary, CalCCA provides the following replies to parties’ opening comments on Track 2 proposals:

LOLE Study Reply Comments
• CalCCA agrees with stakeholders who suggest more time and a structured process for setting the PRM;
• CalCCA supports the RA program’s focus on reliability, though economic efficiency and affordability should be considered in setting PRMs;
• CalCCA agrees with stakeholders who request further clarification and analysis of the inputs and assumptions used in SERVM modeling;
• CalCCA supports consistency between data used in SERVM modeling, SOD PRM translation, and SOD accreditation;
• CalCCA disputes Microsoft’s recommendation that only the LOLE study be used in setting the PRM; and
• CalCCA encourages the development of a methodology to determine monthly or seasonal PRMs.
3 Local RA CPE Reply Comments
• The Commission should reject PG&E’s proposal to provide the local RA CPEs with LSE procurement information in advance of its solicitations and SCE’s modification to the proposal;
• The Commission should dismiss parties’ misguided concerns about the CalCCA CPE timeline proposal;
• CalCCA agrees with parties that the long-term local area resource transition is best addressed in the IRP proceeding; and
• The AReM should clarify how the CAISO would allocate local CPM costs.

II. LOLE STUDY REPLY COMMENTS
A. CalCCA Agrees with Stakeholders Who Suggest More Time and a Structured Process for Setting the PRM
AReM recommends that the Commission consider separating the PRM from the forthcoming Track 2 decision so that stakeholders have time to review the revised tools and analysis.
4 CAISO recommends that the current study should not be used to set the 2027 PRM.5 CalCCA agrees with these parties. Instead of adopting the 2026 and 2027 PRM within the Track 2 decision, CalCCA recommends: (1) that the Commission adopt AReM’s recommendation to consider the 2026 PRM in a later decision, and (2) that Energy Division use the current inputs and assumptions to calculate a 2027 PRM only for informational purposes to aid planners in making procurement decisions. The Commission should then set the final 2027 PRM the following year using updated inputs and assumptions.

CalCCA also supports parties’ recommendations that the Commission establish a regular schedule and process for the LOLE study and PRM setting with stakeholder input.6 A regular 4 AReM Opening Comments at 5.
5 CAISO Opening Comments at 4.
6 San Diego Gas and Electric Company (SDG&E) Opening Comments at 2-4; Calpine Corporation (Calpine) Opening Comments at 6; MRP Opening Comments at 5; and Microsoft Opening Comments at 9. 4 schedule and process will ensure the PRM continues to meet reliability standards as inputs and assumptions evolve while providing stakeholders sufficient opportunities to understand and vet the results.

B. CalCCA Supports the RA Program’s Focus on Reliability, Though Economic Efficiency and Affordability Should be Considered in Setting PRMs Parties ask the Commission to formally adopt a 1-in-10 LOLE reliability standard for the RA program.7 Some of the same parties also support the continued evaluation of additional reliability metrics in the reliability studies used to set the PRM. 8 CalCCA agrees that the primary consideration of the RA program is ensuring a reliable system and that the current industry definition of a reliable system is one that meets a 1-in-10 LOLE. However, the focus on reliability should not lose sight of the implications for affordability. The $60 million per year cost of increasing the PRM by 1 percent, 9 for example,
should be justified by a corresponding decrease in the expected societal cost of power outages.

With a value of lost load of $10-14/ kilowatt-hour (kWh) of unmet load found in a recent survey of California residents,
10 a $60 million per year increase in costs is warranted if it avoids at least 4,000 megawatt-hour (MWh) per year of unmet load. The Energy Division’s LOLE study finds 7 SDG&E Opening Comments at 4-6; CAISO Opening Comments at 2; Middle River Power LLC (MRP) Opening Comments at 6; and Microsoft Opening Comments at 2. 8 CAISO Opening Comments at 2; MRP Opening Comments at 6; Microsoft Opening Comments at 10; Calpine Opening Comments at 9.
9 Average peak managed load across 2026 is 36,283 MW in each month (CEC IEPR 2023 Planning Forecast). Assuming CPUC-jurisdictional loads are 90% of the CAISO peak, the average CPUC peak is 32,655 MW. The incremental cost of a 1% increase in the PRM, assuming RA costs of the current market price benchmark of $15.23/kW-mo, is therefore 32,655 MW*12mo/yr*15.23/kW-mo*1000kW/MW*1% = $60 million/yr. The cost impact could be greater if scarcity in the RA market drives prices higher as the PRM goes higher.
10 Gorman and Callaway (2024) conducted an open-ended stated-preference experiment with California residents to estimate household willingness-to-pay (WTP) to avoid outages. They calculated an average VoLL of $10–14/kWh, within the range of estimates in prior work. Gorman, W. and D.

Callaway. "Do notifications affect households’ willingness to pay to avoid power outages? Evidence from an experimental stated-preference survey in California." The Electricity Journal 37, no. 3 (2024): 107385. 5 that a 1-in-10 LOLE results in at most 160-492 MWh of unmet load, far below the level required to economically justify any further increase in PRM. With the current extraordinary costs for resource adequacy, changes in the PRM should be carefully substantiated.

Along with any adoption of a reliability target, the Commission should demarcate plausible conditions that are to be addressed through the PRM and extreme conditions best left to out-of-market mechanisms. For example, during the July 25 workshop, parties suggested adding the loss of imports over interties as a consideration in the LOLE study. Essentially, these parties ask for the Commission to determine a PRM needed for conditions beyond the 1-in-10 reliability standard generally supported by parties for the RA program. Adding more and more extreme planning conditions to the list of potential contingencies that could contribute to loss of load events would likely increase the PRM needed to meet the 1-in-10 LOLE standard. However, mechanisms like the Strategic Reliability Reserve are designed to maintain grid operations in conditions that go above and beyond reasonable planned conditions.11 Incorporating the same extreme conditions when setting the PRM and when designing the Strategic Reliability Reserve risks a double hit to ratepayers, first through electricity bills and second through taxes.

C. CalCCA Agrees with Stakeholders Who Request Further Clarification and Analysis of the Inputs and Assumptions Used in SERVM Modeling CalCCA is concerned that the high PRM found in the Commission’s 2026 LOLE study and subsequent revisions to the SOD PRM Tool is, in part, due to issues with the inputs and assumptions used in SERVM modeling. CalCCA agrees with MRP that the choice of calibrating 11 The CEC’s California Energy Resource and Reliability Outlook, 2024 notes that “…the continued development of the SRR [Strategic Reliability Reserve] ensures that programs are available for addressing reliability risks during extreme events.” (at 54):
https://efiling.energy.ca.gov/GetDocument.aspx?tn=258494&DocumentContentId=94524. 6 Commission load profiles to Integrated Energy Policy Report (IEPR) Consumption or IEPR Managed Load may have a substantial impact on the PRM.
12 CalCCA compared the Commission’s managed load profile on the peak load day for the September 2022 and August 2020 weather year to historical load profiles observed by CAISO.

The Commission’s managed load profiles appear to be shifted in time toward later in the day, beyond what would be expected because of BTM PV growth in 2026. Additional details of the analysis are included in the appendix. This unexpected shift should be investigated by the Commission, and the Commission should test if the same shift occurs when calibrating to the IEPR Consumption. High peak loads later in the day will likely understate the reliability contribution of the baseline resources and, as a result, overstate the PRM required to achieve the 1-in-10 reliability target.

CalCCA also agrees with the California Energy Storage Alliance (CESA) and PG&E that the process for developing storage outage rates requires further clarification. 13 Storage outage
rates used in SERVM should only reflect storage plant failures, not unavailability due to state-of-charge as suggested by the CAISO Department of Market Monitoring, since SERVM presumably manages state-of-charge to dispatch storage in the model. The Commission explained in its inputs and assumptions document that because battery storage resources do not yet report to the North American Electric Reliability Corporation’s Generating Availability Data System, it uses data from the CAISO’s outage management system to estimate energy storage forced outage rates.

Specifically, “[s]taff engaged in a series of meetings to review the CAISO curtailment outage types and natures-of-work with various stakeholders to determine which curtailments should be included in [the effective forced outage rate (EFOR)],” and provided a list of the forced outage 12 MRP Opening Comments at 8.
13 CESA Opening Comments at 3-5; and PG&E Opening Comments at 10. 7 natures-of-work in its calculation.14 The Commission, in collaboration with the CAISO, should provide increased transparency regarding the natures-of-work the Commission included in its calculation and under what conditions battery storage resources are expected to submit such outages that will impact the resources EFOR. This will ensure the calculation only includes true resource unavailability because of a forced outage rather than apparent unavailability due to the economics of CAISO market dispatch of a use-limited resource. Finally, CalCCA supports parties’ requests to review the underlying data for generator outage rates and to consider seasonal forced outage rates for winter and summer in SERVM modeling.15 D. CalCCA Supports Consistency Between Data Used in SERVM Modeling, SOD PRM Translation, and SOD Accreditation
Several parties commented on data used in SERVM modeling, SOD PRM translation, and SOD accreditation of resources. CalCCA supports further validation and clarification of approaches used by the Energy Division. In adjusting the data and methodologies, the Commission should ensure that the revised approaches maintain consistency between SERVM modeling, SOD PRM translation, and SOD accreditation. The consequence of differences in representation in SERVM and the SOD PRM translation tool is a choice of PRM that does not achieve the intended 0.1 LOLE.

Specifically, CalCCA agrees with parties that the dispatch of storage in the SOD PRM Tool is flawed and does not maximize the reliability contribution of storage.16 CalCCA also agrees that the storage dispatch in the SOD PRM Tool should be benchmarked to SERVM dispatch of storage to verify that the accreditation of storage is consistent with the capabilities of 14 Administrative Law Judge’s Ruling on Energy Division’s Proposed Inputs & Assumptions, R.23- 10-011 (Mar. 18, 2024), at 34:
https://docs.cpuc.ca.gov/SearchRes.aspx?DocFormat=ALL&DocID=527532337. 15 Calpine Opening Comments at 3; and PG&E Opening Comments at 10. 16 SCE Opening Comments at 5.
8 storage represented in SERVM.17 Similarly, the wind and solar profiles in the SOD PRM Tool should align with the profiles in SERVM, as noted by SCE.18 Other parties comment on ways to better validate or improve SERVM modeling of ambient derates19 or geothermal performance degradation.20 CalCCA recommends that such limits on the performance and availability of resources should be addressed through SOD resource accreditation rather than the PRM where possible. Including resource performance and availability in the PRM shifts the burden of generator unavailability from the party that can control the unavailability (the generator) to the party that cannot (the LSE). This removes the incentive for generators to conduct planned maintenance at times that minimize the impact on system reliability and adds additional demand to an RA capacity market that is already scarce.

E. CalCCA Disputes Microsoft’s Recommendation that Only the LOLE Study be Used in Setting the PRM
Microsoft suggests the Commission not use the SOD PRM Tool in setting the PRM and instead have the PRM come only from the SERVM LOLE study.21 This recommendation should be rejected as it misrepresents the information produced by the LOLE study. Figure 1 illustrates the relationship between the reliability modeling in SERVM and the quantification of reserves outside of the SERVM LOLE study.
17 The Public Advocates Office at the California Public Utilities Commission’s (Cal Advocates) Opening Comments at 10-11.
18 SCE Opening Comments at 4.
19 PG&E Opening Comments at 9; and Calpine Opening Comments at 3. 20 Cal Advocates’ Opening Comments at 4.
21 Microsoft Opening Comments at 11.
9 Figure 1.

Quantification of Reserves Provided by the Calibrated Baseline Portfolio In the LOLE study, SERVM is used to simulate the ability of the Calibrated Baseline Portfolio to meet hourly loads derived from 23 years of weather profiles, subject to generator outages and variability in wind, solar, and hydropower availability. The SERVM model shows that the Calibrated Baseline Portfolio is reliable in that it achieves the target 0.1 LOLE. On its own, the SERVM model does not specify or quantify planning reserves. Instead, the reserves provided by the Calibrated Baseline Portfolio are quantified outside of the SERVM model using SOD accreditation rules. The SOD PRM Tool translates the nameplate capacity of resources in the Calibrated Baseline Portfolio into a quantity of accredited supply for each month and hour of the peak day based on SOD profiles and rules. The accredited supply of the Calibrated Baseline Portfolio is then compared to the 1-in-2 peak day demand profile for each month. The amount the accredited supply exceeds the 1-in-2 peak demand is the achieved capacity margin under the SOD rules. The Commission’s process then uses the achieved capacity margin as a percentage of 1-in-2 peak demand to inform the choice of the planning reserve margin (PRM). The PRM is, therefore, intertwined with the rules used to accredit the supply of the Calibrated Baseline Portfolio; a different set of rules would produce a different amount of achieved capacity margin and a different choice of PRM. It is not possible to separate the definition of the PRM and the Calibrated Baseline
Portfolio

0.1 LOLE
SERVM Model
Achieved
Capacity Margin
with SOD
10 accreditation of supply. The Commission should, therefore, reject Microsoft’s recommendation to derive the PRM only from SERVM.

F. CalCCA Encourages the Development of a Methodology to Determine Monthly or Seasonal PRMs
Parties encourage the Commission to conduct more granular analysis and determine the best PRMs tailored to seasonal monthly periods,22 support Vistra’s proposal for seasonal PRMs and encourage further workshops,
23 and request an evaluation of whether a monthly or seasonal PRM framework could introduce ratepayer savings.24 A prerequisite of adopting seasonal or monthly PRM is further development of the LOLE/PRM study process to identify how the fundamental relationship between reserves and loss of load varies from one month to another.

Underpinning the idea of a monthly or seasonal PRM is an expectation that the risk of unmet load for a specific level of planning reserves differs across the year. Depending on weather patterns, variability of demand around the 1-in-2 peak demand will differ from month-to-month, along with variability of wind and solar around the level accredited in the SOD accreditation rules. Potentially each month will therefore have a unique relationship between the risk of unmet load and the reserve margin, illustrated in Figure 2. A month with greater variability, illustrated by Month A, will potentially require more reserves than a month with less variability, illustrated by Month B, to achieve the same risk of unmet load. 22 SCE Opening Comments at 7.
23 Microsoft Opening Comments at 5.
24 Cal Advocates Opening Comments at 4-10.
11 Figure 2.

Illustration of Information from SERVM Model to Identify Unique Risk-Reserve Relationships by Month
The Commissions current study process does not sufficiently characterize this risk-reserve relationship for each month. Instead, the current monthly stress test only finds the risk of unmet load for a single target reserve margin. The Commission should encourage Energy Division to expand the analysis to report the monthly LOLE across a range of reserve margins.

With this information, the Energy Division and stakeholders could evaluate how various choices of reserve margins in each month or season can be used to allocate the annual 0.1 LOLE budget.

CalCCA agrees with the Cal Advocates that the justification for moving to a monthly or seasonal PRM should be based on ratepayer savings.25 The lowest costs to ratepayers can be 25 Cal Advocates Opening Comments at 4-10.

Risk of Unmet Load
Characteristic
Risk-Reserve
Curve for
Month A
Limit risk by keeping
Reserve Margin at this
level or higher in
Month A I
I
I •
I
Reserve Margin
(% of Demand)
12 achieved by allocating the annual 0.1 LOLE budget to months where procuring additional reserves is the most expensive. As a result, the reserve margin in the low reserve price months may have to be set to elevated levels such that the LOLE for the low reserve price months is near zero. A simple stack analysis using the Baseline Portfolio, SOD accreditation rules, and the 1-in-2 peak day forecast for 2026 can aid in identifying the months where net supply is expected to be tightest, and RA will likely be most expensive.

III. LOCAL RA CPE REPLY COMMENTS
A. The Commission Should Reject PG&E’s Proposal to Provide the Local RA CPEs with LSE Procurement Information in Advance of Its Solicitations and SCE’s Modification to the Proposal
SCE supports PG&E’s proposal to allow CPEs to collect information from Energy Division regarding local RA capacity already under contract with LSEs with modifications to address changes between when the CPE receives the information and the year-ahead filings.26 CalCCA continues to recommend the Commission reject the investor owned utilities’ (IOUs’) proposals, including PG&E’s proposal with SCE’s modifications because it is unclear the intended purpose of having this information and what benefits it will provide. It is also not clear, as Cal Advocates state, “how the CPE will use the collected data to inform its solicitation and decision-making.27 If the IOUs know that the resource is under contract to a Commission-jurisdictional LSE, the proposal seems to imply that the CPEs would then forego procuring the resource for local RA entirely.

This fundamentally alters the original CPE design that allowed any entity, including LSEs who no longer have local RA obligations, to offer to sell local RA to the CPE with equal opportunity of being procured. It may be possible to aggregate the data to prevent revealing 26 SCE Opening Comments at 12.
27 Cal Advocates Opening Comments at 13.
13 information about individual LSE portfolios. However, providing the CPE with information about the local resources already under contract at an aggregate level provides the CPE with information that it may use to avoid procurement of local resources offered in its solicitations by LSEs or self-shown for compensation. This would effectively allow CPEs to take the value of local resources for free.

This also assumes the LSE that has it under contract will use it on its RA plan even though it may or may not. It could sell the resource to another LSE or out-of-state entity or hold the resource for substitution. The Commission should not adopt the IOUs’ proposal to modify the voluntary self-showing process, as doing so would likely take away LSEs’ opportunities to self-show the resource for compensation or sell it without providing useful information to the CPE.

B. The Commission Should Dismiss Parties’ Misguided Concerns about the CalCCA CPE Timeline Proposal
While parties recognize the timing constraints put on LSEs waiting for CPE allocations,28 and the challenge these timing constraints present for LSE procurement planning,29 they recommend that the Commission reject CalCCA’s proposal to modify the CPE timeline. These parties cite concerns that CalCCA’s proposal will disincentivize self-showing, result in CPE overprocurement, or not achieve CalCCA’s desired objective of providing LSEs with more certainty of the amounts of CPE allocations they will receive. For the reasons described below, these parties' concerns with CalCCA’s proposal are misguided, and the Commission should reject them.
28 SCE Opening Comments at 10.
29 Cal Advocates at 15.
14 SCE suggests:
... CalCCA’s proposal will not accomplish the intended objective because it will discourage LSEs from timely self-showing resources... As a result of a lack of self-shown resources, the CPE may procure compensated resources to meet its compliance targets, effectively over-procuring to meet the perceived compliance need because the self-shown resources that are available in the prompt + 1 will likely not materialize in the CPE’s portfolio until the next year’s solicitation. The costs of over procurement are then allocated to all LSEs through the CAM, resulting in the CPE procuring above its compliance targets and providing that system RA to LSEs rather than LSEs procuring their own system RA.30
CalCCA’s proposal31 simply moves the timing back to that originally established for the CPE.32 There is no reason an LSE that has procured a local resource multiple years forward would not be willing to self-show a local area resource. In fact, the CPE report issued by the Energy Division shows that in the first solicitation, the majority of local resources for the LA Basin and Big Creek Ventura area came from self-shown resources as depicted in Table 333 from that report.
30 SCE Opening Comments at 10-11.
31 California Community Choice Association’s Proposals on Assigned Commissioner’s Scoping Memo and Ruling Track 2 Central Procurement Entity Framework and IRP Coordination, R.23-10-011 (June 14, 2024): https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M533/K837/533837255.PDF. 32 D.20-06-002, Decision on Central Procurement of the Resource Adequacy Program (June 12, 2020), at 69-70.
33 Report on the 2021-2023 Central Procurement Entity Framework May 31, 2024, at 19:
https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/resource-adequacy-homepage/resource-adequacy-compliance-materials/useful-resources/final-report-on-the-2021-2023-cpe-framework.pdf. 15 Given the significant volumes of self-shown resources for 2023 and 2024 in a 2021 solicitation, SCEs claim that changing to timeline back to what it was upon implementation of the CPE lacks credibility.

Cal Advocates suggests that CalCCA will not achieve its required objectives because:
“CalCCA’s proposal would require the CPEs to procure to meet targets two years before the compliance year. The two-year gap creates risks that CPE procurement may not account for variables that affect year-over-year CPE procurement targets... CalCCA’s proposal still allows the CPE to perform incremental procurement to make up for changes to the local RA need since its last annual solicitation. CalCCA states that the change in local RA need year over year is “typically small” and should have minimal impact on adjustments to CPE Credits. Cal Advocates disagrees.”34 34 Cal Advocates Opening Comments at 16, footnotes omitted.

Table 3 . .2021 SCE-CPE RFO Results
2021 SCE~CPE RFO Results for LA Ba5in (LAB) and Big Creek/Ventura (BCV) LCAs S@Jler Contract Type Re:So111ru· Types LCA No. of Contracts Pel\lod and Contracted Cap,adty (MW)
SCE Self.Sllow No- Limited Energy LAB 2023, 2024 : 1,117 MW-Comperaation Storage Resource, 2,362 MW Combined Cycle 55 2023, 2024: 330 MW - BCV
Natural Gas, Steam 660MW
Natural Gas
Wind, Solar PV
Hydro
eai n Power Self.Sllow No• Combined Cycle LAB 2023, 2024 : 24 MW- 248 Allla,nce of Comp@llisation Natural Gas, Solar MW
Southern PV 5
Calliforn a BCV 2023, 2024 : SO MW - 202
jCPASC} MW
Desert Self.Sllow No- Combined Cycle 2023-2024: 2 MW - 24 Community Compensation Natural Gas, Solar LAB 3
MW
Energy I DOE) Self.Sllow L.CR
RCM
PV, Wind
1 1MW-4MW
Wa lnut Creek: RA Only Combustion Tur b ne LAB 1
J'Un. 1, .2023 - ID@;c. 3!1,
Energy LLC Nawral Gas 2026: 483 MW
16 Cal Advocates then compares changes between the two-year ahead (Y+2) local capacity requirement (LCR) estimates against the year-ahead (Y+1) LCRs for the same compliance year.

Cal Advocates states first that “Negative values indicate that the CPE would have over-procured in its solicitation two years before the compliance year.”35 First, the potential for the CPE to procure more in Y+2 than the ultimate LCR in Y+1 due to downward changes in LCRs is not a function of CalCCA’s proposal to shift the timeline. Under the existing local RA CPE timeline, LCRs can decrease from Y+2 and Y+1 and if the CPE procures 100 percent of its Y+2 LCR, as required, then the CPE would still be overprocured after the LCR reduction in this scenario.

Second, while SCE and Cal Advocates express concern about overprocurement associated with CalCCA’s proposal, it is the failure to resolve the timing issues that will actually risk overprocurement. If CPE allocations are allocated well enough in advance, LSEs have time to adjust their procurement plans to take into account these allocations, including selling off excess RA if their CPE allocations make them long. If, instead, LSEs overprocure because they cannot predict their CPE allocations, they will not be made aware that they overprocured until it is too late to adjust their procurement.

Cal Advocates then states that “For the PG&E CPE, CalCCA’s proposal would have resulted in between 538 megawatts (MW) and 1,429 MW of incremental procurement in the last three years had the proposal been implemented” and that “[s]uch a substantial increase in CPE Credits undermines CalCCA’s stated goal to mitigate CPE Credit allocation uncertainty.”36 The Commission should not view this as a substantial increase. PG&E’s 2023 local RA requirement was 11,543 MW, the incremental change between Y+2 and Y+1 (1,429 MW) is only 12 percent.

This should not be considered “substantial” relative to the largest PG&E Y+2 shortfall of almost 35 Cal Advocates Opening Comments at 16.
36 Id. at 17.
17 40 percent of the requirement. In addition, Cal Advocates misses the point that regardless of the timing of the CPE, any change that increases the LCR must be procured or it will risk reliability in the local area. The CPE procuring for the incremental change and its Y+2 deficiency is a much more substantial change and creates much more uncertainty than providing the LSE its allocations after Y+2 and only updating those allocations for any procurement completed for the 1,429 MW change.

Cal Advocates suggests instead that LSEs can estimate their allocations by looking at the Y+2 procurement volumes on the CPUC website and applying their load ratio shares.37 This is not true when the CPEs come up significantly short in Y+2, which has happened in 2023 and 2024 in the PG&E CPE territory, followed by the additional CPE procurement for any incremental changes in Y+2 and Y+1 requirements plus Y+2 deficiencies in Y+1. Again, if LSEs estimated their allocations based upon the results of CPE procurement in Y+2 and then the CPE resolves its entire deficiency from Y+2 in Y+1, then the LSE would have significantly overestimated its procurement obligations and overprocured. For these reasons, the Commission should reject party recommendations to reject the CalCCA local RA CPE timeline proposal.

C. CalCCA Agrees with Parties that the Long-Term Local Area Resource Transition is Best Addressed in the IRP Proceeding
CalCCA agrees with CESA that repurposing the CPE’s focus to procure gas plants and new clean resources in local areas to address future retirements “change[s] the overall purpose of the local RA program from ensuring sufficient local RA will be operationally available to CAISO (via RA Plan and Supply Plan compliance) to a long-term planning and procurement exercise.

Managing the long-term local area resource transition is best addressed in the IRP process.”38 37 Cal Advocates Opening Comments at 18.
38 CESA Opening Comments at 9.
18 A coordinated view of the resources and transmission available to replace gas or reduce local constraints is key to reducing reliance on gas resources in local areas. If the Commission addressed the transition from reliance on gas resources in local areas in the RA proceeding through repurposing the CPE, the key linkage between resource planning and transmission planning would be missing. The IRP proceeding already links to the CAISO’s Transmission Planning Process. Failure to consider transmission solutions when addressing local area reliability presupposes the most cost-effective solution to minimizing reliance on local gas resources. It also presupposes that expanding the local RA CPE function to procure new local resources is superior to LSE procurement of new local resources. The Commission should, therefore, develop a methodology for planning for reduced reliance on local gas resources in the Reliable and Clean Power Procurement Program (RCPPP) in coordination with the TPP, rather than repurposing the CPE.

Parties who recommend eliminating the five-year limit on CPE procurement times or encouraging the CPE to contact for longer terms do so on the grounds of supporting new resource development39 or facilitating procurement of local resources needed for local reliability during the energy transition.40 These recommendations again presuppose the outcome of the RCPPP, where the Commission is considering a process for new resource development, including new resource development in local areas and the retention of existing resources necessary to support reliability during the energy transition. Given the interactions between the IRP, TPP, and local area needs, the Commission should refrain from adopting policies here that expand the use of the local RA CPE without evaluating if it makes sense for the local RA CPE to play a role within the context of these broader processes. 39 New Leaf Energy, Inc. Opening Comments at 2.
40 Calpine Opening Comments at 6.
19 D. AReM Should Clarify How the CAISO Would Allocate Local CPM Costs AReM’s opening comments clarify that its Track 2 proposal to eliminate the CPE framework “does not propose elimination of CAISO local requirements studies. Those studies should continue and if CAISO finds that system RA procurement is inadequate for meeting local requirements, as discussed above, the CPM or CAM should be used on a case-by-case basis to remedy any shortfall.”41 While this clarification is helpful, it leaves open the question of how local CPM costs are allocated if the CAISO has to use its CPM authority to fill a local need. The CAISO’s tariff requires it to first allocate costs to individually deficient LSEs, then collectively to all LSEs serving load in the local areas’ TAC area by gross load share.42 Because no individual LSE would have a local RA requirement, it appears that under AReM’s proposal, costs would be allocated collectively. While this may be satisfactory, the record needs to be informed by specific information on how such cost allocation would occur and if the CAISO tariff would require any changes.

IV. CONCLUSION
For all the foregoing reasons, CalCCA respectfully requests consideration of the recommendations herein and looks forward to an ongoing dialogue with the Commission and stakeholders.

Respectfully submitted,
Evelyn Kahl,
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
August 23, 2024
41 AReM Opening Comments at 3.
42 CAISO Tariff Section 43A.8.3.
t
4 APPENDIX A-1

APPENDIX
TO
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY COMMENTS ON ADMINISTRATIVE LAW JUDGE’S RULING MODIFYING TRACK 2 SCHEDULE

LOAD PROFILE ANALYSIS
Energy Division’s analysis indicates that the 2022 weather year makes the greatest contribution to LOLE of all 23 weather years. The highest consumption and managed load for the CAISO region of the 23-year dataset occurs on a single day with the 2022 September weather year.43 CalCCA finds that the Energy Division’s managed load shape for the peak September 2022 weather year is shifted later in the day compared to the observed CAISO peak managed load,44 inclusive of estimated demand response,45 on September 6, 2022. CalCCA adjusted the Energy Division managed load data to remove the BTM PV growth expected between 2022 and 2026 (about 47 percent more BTMPV in 2026) and to remove the weather-normalized load growth expected between 2022 and 2026 (about seven percent higher consumption in 2026).

Even with this adjustment of the Energy Division managed load shape back to 2022 levels, the Energy Division load shape (red line) appears to peak two hours later in the day than the observed CAISO peak (black line). CalCCA extended the same comparison to the August 18, 2020 peak day46 and found a similar mismatch in the Energy Division load shapes. 43 CalCCA analysis of the Energy Division hourly load data for 2026, at https://files.cpuc.ca.gov/energy/modeling/2024_servm_updates/HourlyLoadComponents_CAISO_2026.csv. 44 CAISO 2022 Production and Curtailments Data:
https://www.caiso.com/documents/productionandcurtailmentsdata_2022.xlsx. 45 September 6, 2022 demand response estimated from Figure 22 of CAISO‘s Summer Market Performance Report for September 2022.
https://www.caiso.com/Documents/SummerMarketPerformanceReportforSeptember2022.pdf. 46 CAISO load data from https://www.caiso.com/documents/productionandcurtailmentsdata_2020.xlsx and demand response data from Figure 3.7 of https://www.caiso.com/Documents/Final-Root-Cause-Analysis-Mid-August-2020- Extreme-Heat-Wave.pdf.

APPENDIX A-2
Figure 1. Comparison of CAISO managed load during September 2022 and August 2020 peak events and the Energy Division’s Managed Load profiles with 2022 and 2020 weather data September 2022 Peak Managed Load Day
55,000
50,000
45,000
40,000 ~ , +---+----+---+--+---+
35,000
30,000
25,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hour Ending PST
- - - - CPUC Managed - 2026 --CAISO Managed (Observed}
- - CPUC Managed - 2022 - CAISO Managed (Reconstitued}
August 2020 Peak Managed Load Day
55,000
50,000
45,000
40,000
35,000
30,000
25,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hour Ending PST
- - - - CPUC Managed - 2026 --CAISO Managed (Observed}
- - CPUC Managed - 2020 - CAISO Managed (Reconstitued}
Contact
Shawn-Dai Linderman ([email protected])

1. Please provide a summary of your organization’s general comments on the meeting regarding alternative proposals.

The California Community Choice Association (CalCCA) appreciates the opportunity to comment on the August 19, 2024, stakeholder call. The CAISO presented a revised schedule, alternative proposals put forth by the California Energy Storage Alliance (CESA) and Vistra Corp. (Vistra), and an analysis of the frequency of storage mitigation to inform potential instances of warranted Bid-Cost Recovery (BCR).

The concerns that the CAISO listed, lack of exposure to real-time (RT) prices and incentives to bid strategically, are legitimate issues that the stakeholder process should address. The CAISO will need to determine how much of each objective can be addressed immediately and which may take a longer-term initiative to address. In summary:

CalCCA thanks the CAISO for extending the schedule of this initiative to allow more time to have a robust discussion of solutions that specifically target unwarranted BCR payments.

The CESA proposal and Vistra proposals warrant additional discussion and consideration. The CAISO should explore the open questions associated with these alternative proposals to allow stakeholders to assess their merits fully.

CalCCA appreciates the CAISO’s presentation of instances of mitigation, including cases in which BCR payments to storage resources would likely be warranted.

The CAISO’s revised schedule, presentation of alternative solutions, and presentations of cases where BCR may be warranted will allow for a more robust discussion of the potential of solutions that effectively address unwarranted BCR payments while providing fair compensation for storage resources.

2. Please provide your organization’s comments regarding the updated schedule of the initiative.

CalCCA appreciates the CAISO’s revised schedule of the initiative, which will provide more time for stakeholders to evaluate and comment on the CAISO’s proposal and stakeholder-proposed alternatives. It will also allow more time to consider which instances warrant BCR, like when resources are mitigated, and the magnitude of those instances. The revised schedule will allow more time to have a robust discussion of solutions that specifically target unwarranted BCR payments. The CAISO should consider whether one of its concerns will be easier to address within the updated schedule than the other. In addition, if one of the two concerns is more difficult to address, the CAISO should evaluate whether it is feasible to put forth proposals that address both within the updated schedule or if an additional phase of the stakeholder process will be necessary.

3. Please provide your organization’s comments regarding the alternative proposals put forth by stakeholders, the outstanding questions regarding their implementation, and how they compare relative to the status quo and the Proposed Solution.

Within the stakeholder initiative, the CAISO should include further examples and description of how BCR is triggered. This information will help stakeholders to better understand the changes being contemplated.

Unwarranted BCR payments can result from the current framework’s disincentives to consider RT market conditions due to limited RT price exposure that could incentivize resources to bid inefficiently to maximize BCR payments. The CAISO and the Department of Market Monitoring have identified an increase in BCR payments California Community Choice Association SUBMITTED 08/26/2024, 02:41 PM 9/3/24, 11:01 AM California ISO - All comments
https://stakeholdercenter.caiso.com/Comments/AllComments/6A3C5D4B-3018-4A56-91BB-9D0B341CAAC2#org-adb2662f-ca44-469e-9452-b6a7a59… 1/2 •
•
•
to storage resources related to the buy-back or sell-back of day-ahead schedules due to state-of-charge constraints. This can create market inefficiencies and increased costs that could be exacerbated by the ability of storage to bid above the soft-offer cap. However, BCR payments are warranted if the buy-back or sell-back results from the CAISO’s market design preventing resources from reflecting RT conditions in the RT energy bids and, therefore, dispatching storage in a way that makes them eligible for BCR. In these cases, BCR is warranted, and the CAISO should aim to develop a solution that differentiates between unwarranted and warranted BCR.

CESA and Vistra proposed alternative solutions to the CAISO’s straw proposal. CESA’s proposal would modify the RT BCR calculation to replace the resource’s RT bid price with the day-ahead energy price. This proposal intends to allow storage resources to continue existing bidding practices without inadvertently increasing BCR payments or offering strategic RT bids to increase revenues through BCR payments. Vistra makes a similar proposal to CESA but would use the resources’ default energy bid rather than the day-ahead energy price in the BCR calculation. It also advances a proposal to exclude resources from BCR in the intervals where the scheduling coordinator has submitted an outage card or bid parameters that derate or rerate the resource. While CalCCA does not take a position on its preferred approach at this time, the CESA and Vistra proposals warrant further consideration, as they could offer improvements to the CAISO’s proposed blunt mechanism for excluding storage resources from BCR. The CAISO should continue to explore the open questions it identified associated with these proposals so that stakeholders can assess the merits of these proposed alternatives.

4. Please provide any other proposals your organization considers the ISO should assess.

Please include as much detail as possible.

CalCCA has no alternative proposals at this time.

5. Please provide your organization’s comments regarding the issues regarding mitigation as well as the initial analyses presented by the ISO.

Stakeholders and the Market Surveillance Committee have noted that if storage is mitigated prior to the buy-back or sell-back, they may warrant BCR payments. This is one case beyond the resource operator’s control that can prevent a resource from having sufficient state of charge to follow its day-ahead schedule and prevent it from recovering its costs fully through market participation. The CAISO’s presentation indicates that about 41 percent of BCR payments to storage were paid to mitigated resources. This number is not insignificant and signals that the ultimate solution must consider instances where BCR is warranted.

6. Please provide any additional comments, feedback, or examples regarding the stakeholder meeting. You may upload examples or data using the “Attachments” field below.

CalCCA has no additional comments at this time.
9/3/24, 11:01 AM California ISO - All comments
https://stakeholdercenter.caiso.com/Comments/AllComments/6A3C5D4B-3018-4A56-91BB-9D0B341CAAC2#org-adb2662f-ca44-469e-9452-b6a7a59… 2/2 1 August 26, 2024
California Public Utilities Commission – Energy Division Attention: Tariff Unit
505 Van Ness Avenue
San Francisco, CA 94102
Via email to [email protected]
Re: Joint Community Choice Aggregators’ Response to the Self-Generation Incentive Program (SGIP) Program Administrators’ Advice Letter Proposing Revisions to the SGIP Handbook (Southern California Edison Company’s Advice Letter 5347-E et al.) To the Energy Division’s Tariff Unit:

Pursuant to Rule 7.4.1 of the California Public Utilities Commission’s (Commission) General Order 96-B,1 Ava Community Energy, Clean Power Alliance of Southern California (Clean Power Alliance), Marin Clean Energy, Peninsula Clean Energy, San Diego Community Power, San José Clean Energy, and Sonoma Clean Power Authority (collectively the “Joint CCAs”) submit this Response to the Self-Generation Incentive Program (SGIP) Program Administrators’ (PA) Tier 2 Advice Letter2 proposing revisions to the SGIP Handbook pursuant to Ordering Paragraph (OP) 23 of Decision (D.) 24-03-071, submitted on August 5, 2024 (Advice Letter or AL).

The Commission’s General Rules allow a party to submit a response for the purposes of providing useful information related to the advice letter, as opposed to a protest, which objects in whole or in part to the relief requested in the advice letter.3 The Joint CCAs provide this response in order to provide the Commission information—and seek clarification—regarding: (1) the requirement that customers installing an energy storage project participate in a qualified demand response (DR) program, and (2) the requirement that customers participating in the Residential Solar and Storage Equity (RSSE) and Equity Resiliency Budgets demonstrate income verification in their Reservation Request Form (RRF) for the California Alternate Rates for Energy (CARE) or Family Electric Rate Assistance Program (FERA).

With respect to the qualified DR program participation requirement, the current requirements in the SGIP Handbook risks forcing residential unbundled customers—roughly 50 percent of customers statewide—to forego SGIP storage budget incentives or opt out of community choice aggregator (CCA) service in order to receive those incentives. With respect to the CARE/FERA proof of income verification requirement, the SGIP Handbook risks creating new, unnecessary barriers to participation among customers that have historically had limited 1 General Order No. 96-B, General Rules sec. 7.4.1 (GO 96-B). 2 Southern California Edison Company Advice Letter (AL) 5347-E, Center for Sustainable Energy AL157-E, Southern California Gas Company AL 6350-G, and Pacific Gas and Electric Company AL 4952-G/7345-E (AL 5347-E et al).
3 GO 96-B, General Rules sec. 7.4.1.
2 access to SGIP funding, undermining the goals of the Commission’s Environmental and Social Justice Action Plan.
4 As further described below, the Joint CCAs therefore request the Commission issue a disposition letter or otherwise clarify that:
• The SGIP PAs are permitted to exempt CCA customers from the DR program participation requirement to the extent a qualified DR program is not available to that customer; • The DR programs currently included in Appendix E to D.24-03-071 are not available or accessible to residential CCA customers;
• SGIP PAs must categorically exempt residential CCA customers from the DR program participation requirements until either: (1) the residential CCA customer is eligible to participate and may self-enroll in a CCA DR program that is included on the SGIP Qualified DR Program List; or (2) the residential CCA customer has access to an investor-owned utility (IOU) DR Program on the SGIP Qualified DR Program List at the time the RRF is submitted;
• CCAs are permitted to file Tier 2 advice letters adding CCA programs to the list of qualified DR programs for SGIP purposes;
• CCAs seeking to add their programs to the list of qualified DR programs for SGIP purposes must demonstrate the same requirements as established for POU customers,5 and; • Enrollment in CARE or FERA rates can be demonstrated with the submission of the customer’s utility bill.

I. Qualified DR Program Participation Requirement
A. The SGIP List of Qualified DR Programs Are Not Available or Accessible to Residential CCA Customers.

D.24-03-071 requires that new customers in any storage budget category seeking SGIP incentives enroll in one of eight “qualified DR programs” listed in Appendix E to that decision (“SGIP List of Qualified DR Programs”).
6 To date, that list includes only IOU-administered critical peak pricing (CPP) programs and capacity bidding programs (CBP).7 Those programs are not available or accessible to residential CCA customers.
4 CPUC, ESJ Action Plan (Vol. 2), April 2022, available at: https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/news-and-outreach/documents/news-office/key-issues/esj/esj-action-plan-v2jw.pdf, p.

23. (“GOAL 2: INCREASE INVESTMENT IN CLEAN ENERGY RESOURCES TO BENEFIT ESJ COMMUNITIES, ESPECIALLY TO IMPROVE LOCAL AIR QUALITY AND PUBLIC HEALTH”). 5 D.24-03-071 at 76 (paragraph 7).
6 Id., at 75.
7 Id., Appendix E.
3 CPP programs are available only to bundled customers. 8 And while the IOUs’ CBP
programs are nominally open to both residential and non-residential customers, PG&E, SCE and SDG&E market their programs only to non-residential customers, which means that no residential aggregators currently participate in the IOUs’ CBPs.
9 Further, under program rules, the Joint
CCAs’ understanding is that an individual residential customer could not personally enroll in the IOUs’ CBPs.10 Thus, as a practical matter, CBPs are not available to residential CCA customers because residential customers currently have no pathway to enroll in those programs.

The Joint CCAs acknowledge that D.24-03-071 allows CCAs to develop their own qualified DR programs. Indeed, CCAs continue to develop and offer a diverse range of DR programs, and certain CCAs have developed or are developing DR programs that meet the “qualified DR program” criteria established in D.24-03-071. To the extent a CCA DR program is added to the SGIP list of qualified DR programs,11 residential customers of that CCA would be able to access a qualified DR program.

With that said, the fact that CCA programs may be added to the list of qualified DR programs in the future is not a practical, near-term solution for the vast majority of residential CCA customers seeking (and otherwise eligible for) SGIP incentives. It is not reasonable to expect a CCA to develop an entire new DR program simply to allow its customers to access SGIP funds.

Critically, launching a new program takes time and resources in addition to often requiring complementary regulatory processes. CCAs that have not already made significant progress in developing “qualified DR programs” are unlikely to develop and launch a program in time for their customers to access SGIP funds.
12 In sum, the programs included in the SGIP List of Qualified DR Programs are not available to residential CCA customers. Unless those customers are promptly and efficiently exempted from the qualified DR program participation requirement (as discussed below), those customers will be required to either forego SGIP incentives or opt out of CCA service in order to receive SGIP incentives— at least one CCA has already received inquiries from customers considering opting 8 PG&E’s CPP programs include the SmartRate for residential customers and Peak Day Pricing (PDP) for non-residential customers. See PG&E SmartRate tariff, available at:
https://www.pge.com/tariffs/assets/pdf/tariffbook/ELEC_SCHEDS_E-RSMART.pdf; See PG&E “Peak Day Pricing”, available at: https://www.pge.com/en/account/rate-plans/find-your-best-rate-plan/peak-day-pricing.html.; SCE Schedule CPP (Critical Peak Pricing). 9 The Joint CCAs acknowledge that third parties could, in theory, aggregate residential CCA customers to participate in the relevant IOU’s CBP. That option, however, does not make the CBP “available” to residential CCA customers, because it is predicated on (currently non-existent) market interest. CCAs cannot require third parties to aggregate their residential customers for CBP purposes. 10 See, e.g., PG&E Electric Schedule E-CBP (Capacity Bidding Program); SCE Schedule CBP (Capacity Bidding Program); SDG&E Schedule CBP (Capacity Bidding Program). 11 The Joint CCAs discuss their concerns related to the process for adding CCA DR programs to the qualified DR program list in Section I.C. of this Response. 12 The proof of participation in a SGIP Qualified DR program occurs with the submission of the Incentive Claim Form (ICF) which, for residential customers, usually occurs within 6-12 months of the initial incentive reservation.
4 out of CCA service and returning to PG&E’s bundled service in order to enroll in SGIP qualifying DR programs.13 That would be an inequitable, anti-competitive, unreasonable and unfair outcome the Commission could not have intended, given that CCA customers pay for SGIP through public purpose program (PPP) rates and must therefore have access to the program’s benefits. To contextualize the scale of this problem, roughly 50 percent of the customers of the three large IOUs are CCA customers and likely even a larger portion of SGIP applicants will be CCA customers. As such, a majority of SGIP applicants could be forced to choose between foregoing SGIP incentives and opting out of CCA service. In order to avoid this outcome, the Commission should establish a process that allows CCA residential customers to be efficiently exempted from the qualified DR program participation requirement (until and unless a qualified DR program is available to those customers). The Joint CCAs describe such a process, below.

B. In Order To Avoid Forcing Customers to Depart CCA Service Just To Receive SGIP Incentives, CCA Residential Customers Must Be Efficiently Exempted From the Qualified DR Program Requirement.

D.24-03-071 permits PAs, in consultation with the SGIP working group, to exempt an applicant from the DR participation requirement if:

1. A non-IOU customer does not have access to qualified DR programs; or

2. A customer would have to forfeit a low-income rate to join a DR program.14 As the Joint CCAs explain above, residential CCA customers must be efficiently exempted from the qualified DR program participation requirement in order to avoid inadvertently forcing those customers to either forego SGIP incentives or opt-out of CCA service.

The Joint CCAs make two recommendations to facilitate streamlined exemptions. First, the Commission should clarify that per D.24-03-071, the SGIP PAs are permitted to exempt CCA customers from the DR program participation requirement to the extent a qualified DR program is not available to that customer. The Commission should further clarify that the DR programs currently included in the SGIP List of Qualified DR Programs are not available or accessible to residential CCA customers.

Second, the Commission should establish a straightforward, streamlined exemption process to ensure all customers without access to a qualified DR program are able to receive SGIP incentives without delay. Unfortunately, the exemption process currently prescribed by the SGIP Handbook is unworkable. That process requires SGIP Working Group (WG) approval for each individual customer exemption.
15 This is an impractical requirement given that roughly 50 percent of SGIP applicants may require exemptions and that the reason for the exemption is the same across all customers.
13 Marin Clean Energy has received inquiries from customers considering opting out of CCA service and returning to PG&E’s bundled service in order to enroll in SGIP qualifying DR programs. 14 D.24-03-071 at 76.
15 SGIP Handbook at Section 6.2.4.
5 The Joint CCAs recommend that SGIP PAs categorically exempt residential CCA customers from the DR program participation requirements until either:

1. The residential CCA customer is eligible to participate and may self-enroll in a CCA DR program that is included on the SGIP Qualified DR Program List; or

2. The residential CCA customer has access to an IOU DR Program readily available for enrollment at the time the RRF is submitted.

To provide customers certainty about their SGIP incentive at the time of the initial incentive reservation, it is not enough to “promise” residential customers access to an SGIP Qualified DR Program at the ICF stage if no enrollment options are available at the RRF stage. Rather, SGIP PAs should add a checkbox to the RRF and ICF forms that allows the customer to request the exemption, along with an attestation that no qualified DR program is available to the customer.

C. The Process for Adding CCA Programs to the Qualified DR Program List Must Be Simplified and Clarified.

D.24-03-071 directs SGIP PAs to add to the SGIP List of Qualified DR Programs “any qualified DR programs that may be offered to statewide customers by other non-IOU electric providers.”16 Based on that direction, the Joint CCAs understand that over time, the list of qualified DR programs can and must grow to include CCA programs meeting the criteria in D.24-03-071.

The process for updating the SGIP List of Qualified DR Programs, however, requires clarification. The Decision does not expressly permit CCAs to file advice letters adding their own programs to the list of qualified DR programs (unlike D.23-12-005, which expressly permits CCAs to submit a Tier 2 Advice Letter identifying DR programs meeting the criteria for a qualified DR program established in that decision).17
CCAs recommend the Commission clarify that CCAs are permitted to file their own advice letters adding CCA programs to the SGIP List of Qualified DR Programs, such that IOUs are not placed in the position of being the “gatekeepers” for that list. Further, the Commission should direct SGIP PAs to update the SGIP List of Qualified DR Programs on the SGIP website within five business days of Commission approval of a CCA’s AL.

Finally, to remove any ambiguity regarding the showing a CCA must make in order for a CCA DR program to be added to the SGIP List of Qualified DR Programs, the Joint CCAs recommend the Commission clarify that CCAs seeking to add their programs to the list must demonstrate the same requirements as established for POU customers, which are as follows:

1. The storage device shifts onsite energy use to off-peak time periods of reduce demand from the grid by offsetting or lowering some or all of the customer’s onsite energy demand;

2. The DR program is not a Reliability Demand Response Resource (RDRR) that is use-limited; and 16 D.24-03-071 at 75-76.
17 D.23-12-005 at 25.
6 3. The load impact from the storage device can be accurately measured and evaluated.18 II. Required Documentation to Confirm CARE/FERA Enrollment.

Residential single-family customers participating in the RSSE or Equity Resiliency Budgets can demonstrate income eligibility by either:

1. Providing documentation showing the Host Customer’s household income is 80% of the area median income or less; or

2. Showing proof of enrollment in the MASH, SOMAH, SASH, DAC-SASH, CARE, FERA or ESA Programs.

If showing income eligibility via enrollment in the CARE, FERA and ESA programs, a participating customer must also prove with the RRF submission that “income verification has been completed as a result of participation in the programs.”19 The Joint CCAs recommend the IOU, rather than the customer, confirm the customer’s enrollment in CARE or FERA. Host customers are already required to submit a utility bill with the RRF submission, and that bill specifically states whether the customer is enrolled in CARE/FERA. As such, host customers should not be required to submit any further documentation to confirm CARE/FERA enrollment. Requiring customers or their SGIP Applicants to provide documentation demonstrating that income verification has been completed as a result of a customer’s enrollment in CARE/FERA is not only impractical (it is unclear what documentation a customer could submit to fulfill this requirement), but also an inequitable and inappropriate burden for a set of customers who have historically had limited access to SGIP incentives.20 The CARE and FERA programs have successfully used self-attestation in the past to avoid the unintentional exclusion of qualifying customers. The Commission should take care not to impose a new burden on CARE/FERA customers should those customers seek SGIP incentives. Instead, CARE/FERA enrollment should simply be proven via the host customer’s utility bill, a document that is already being submitted to the SGIP PA with the RRF submission.

With that said, to the extent the Commission does not waive the requirement that the customer must demonstrate that income verification for CARE/FERA has been completed, the SGIP PAs must more specifically describe the documentation they require. 18 D.24-03-071 at 76 (see paragraph 7).
19 AL 5347-E et al. at 87.
20 See, Comments of California Senate Bill 350 Disadvantaged Communities Advisory Group on Rulemaking 20-05-012 Assigned Commissioner’s Ruling on Improving Self Generation Incentive Program Equity Outcomes and Assembly Bill 209 Implementation at 2 (Dec. 2, 2022) (recommending enabling customers who qualify for CARE/FERA to participate in SGIP without additional paperwork), available at: https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M499/K629/499629300.PDF. 7 III. Conclusion
D.24-03-071 establishes a qualified DR program participation requirement for customers receiving SGIP incentives, but leaves critical gaps in the process for granting exemptions to CCA customers who do not have access to qualified DR programs. Additionally, D.24-03-071 does not present a clear pathway for CCAs to directly add their programs to the list of qualified DR programs as and when they are developed. The SGIP Handbook revisions proposed in AL 5347-E et al. do not fill those gaps. Further, the SGIP Handbook’s requirements related to the demonstration of CARE/FERA enrollment would unnecessarily burden low-income customers.

The Joint CCAs therefore request the Commission issue a disposition letter or otherwise clarify that:
• The SGIP PAs are permitted to exempt CCA customers from the DR program participation requirement to the extent a qualified DR program is not available to that customer;
• The DR programs currently included in Appendix E to D.24-03-071 are not available or accessible to residential CCA customers;
• SGIP PAs must categorically exempt residential CCA customers from the DR program participation requirements until either: (1) the residential CCA customer is eligible to participate and may self-enroll in a CCA DR program that is included on the SGIP Qualified DR Program List; or (2) the residential CCA customer has access to an IOU DR Program on the SGIP Qualified DR Program List at the time the RRF is submitted; • CCAs are permitted to file Tier 2 advice letters adding CCA programs to the list of qualified DR programs for SGIP purposes;
• CCAs seeking to add their programs to the list of qualified DR programs for SGIP purposes must demonstrate the same requirements as established for POU customers,21 and;
• Enrollment in CARE or FERA rates can be demonstrated with the submission of the customer’s utility bill.

The Joint CCAs appreciate Energy Division’s consideration of these comments. 21 D.24-03-071 at 76 (paragraph 7)
8 Respectfully submitted,
/s/ Nikhil Vijaykar
Nikhil Vijaykar
Counsel to Joint CCAs

KEYES & FOX LLP
580 California St. 12th Floor
San Francisco, CA 94104
Email: [email protected]
Phone: (408) 621-3256
cc: [email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
Service Lists: R.20-05-012

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Consider
New Approaches to Disconnections and
Reconnections to Improve Energy Access and
Contain Costs.

R.18-07-005
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S COMMENTS ON THE

PROPOSED DECISION EXTENDING CURRENT PROPORTIONAL ALLOCATION

OF PAYMENT ON PAST-DUE BILLS BETWEEN INVESTOR-OWNED UTILITIES

AND COMMUNITY CHOICE AGGREGATORS
Evelyn Kahl,
General Counsel and Director of Policy
Leanne Bober,
Senior Counsel

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
1121 L Street, Suite 400
Sacramento, CA 95814
Telephone: (510) 980-9459
E-mail: [email protected]
August 28, 2024
i

TABLE OF CONTENTS
I. INTRODUCTION ...............................................................................................................2 II. THE PROPOSED DECISION’S DIRECTIVES FOR THE IOUS TO

CONTINUE THE PROPORTIONAL ALLOCATION METHOD SHOULD
BE ADOPTED .....................................................................................................................3 III. THE COMMISSION SHOULD SPECIFY THE PROPORTIONAL

ALLOCATION METHOD APPLIES TO ALL PAST DUE PAYMENTS,
INCLUDING PARTIAL PAYMENTS ...............................................................................4 IV. THE COMMISSION SHOULD REQUIRE MODIFICATION OF THE
IOUS’ TARIFFS TO REQUIRE THE PROPORTIONAL ALLOCATION
FOR ALL PAST DUE PAYMENTS ..................................................................................5 V. CONCLUSION ....................................................................................................................7

APPENDIX A
ii

TABLE OF AUTHORITIES
California Public Utilities Commission Decisions
D.21-11-014 ................................................................................................................................ 3, 1 California Public Utilities Commission Proceedings
R.18-07-005 ................................................................................................................................ 1, 2 R.21-02-014 ................................................................................................................................ 2, 1 California Public Utilities Commission Rules of Practice and Procedure Rule 14.3 ......................................................................................................................................... 1 iii

SUMMARY OF RECOMMENDATIONS
California Community Choice Association recommends adoption of the Proposed Decision, with the following modifications:
• The California Public Utilities Commission (Commission) should specify that the proportional allocation method is to be applied to all past due payments, including partial payments; and
• The Commission should require the investor-owned utilities to modify their tariffs to apply the proportional allocation method for all past due payments.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Consider
New Approaches to Disconnections and
Reconnections to Improve Energy Access and
Contain Costs.

R.18-07-005
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S COMMENTS ON THE

PROPOSED DECISION EXTENDING CURRENT PROPORTIONAL ALLOCATION

OF PAYMENT ON PAST-DUE BILLS BETWEEN INVESTOR-OWNED UTILITIES

AND COMMUNITY CHOICE AGGREGATORS
The California Community Choice Association1 (CalCCA) submits these comments pursuant to Rule 14.3 of the California Public Utilities Commission’s (Commission) Rules of Practice and Procedure2
on the proposed Decision Extending Current Proportional Allocation of Payment on Past-Due Bills Between Investor-Owned Utilities and Community Choice Aggregators3 (Proposed Decision), dated August 8, 2024. The Proposed Decision directs Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric Company (SDG&E) (collectively, the IOUS) to continue to allocate all payments, 1 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. 2 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. 3 Proposed Decision Extending Current Proportional Allocation of Payment on Past-Due Bills Between Investor-Owned Utilities and Community Choice Aggregators, Rulemaking (R.) 18-07-005 (Aug. 8, 2024): http://docs.cpuc.ca.gov/SearchRes.aspx?DocFormat=ALL&DocID=537555377. 2 including partial payments, made on past-due electric utility bills between the IOUs and community choice aggregators (CCA), based on their proportionate share of those past-due bills unless and until the Commission orders otherwise.

I. INTRODUCTION
CalCCA supports the Proposed Decision’s indefinite extension of the proportional allocation method for all past due payments, including partial payments. The Proposed Decision prohibits the IOUs from utilizing the “waterfall” method, which is the IOU standard practice of crediting customer partial payments on delinquent unbundled customer accounts first to the IOU portion of the bill until the customer account is no longer subject to disconnection for delinquency, and only then to the CCA bill portion. As noted in CalCCA’s comments and reply comments on the March 22, 2024 Ruling requesting comments on the waterfall and proportional allocation methods,4 the waterfall method is not required by statute or Commission directive.

Rather, it is embedded in the Commission-approved IOU tariffs. After the waterfall was suspended multiple times during the COVID pandemic, the Commission in Decision (D.) 21-11- 0145
extended the waterfall suspension through September, 2024. Once adopted, this Proposed Decision will continue both the suspension of the waterfall, and the requirement that the IOUs allocate partial past due payments proportionately between the IOUs and CCAs “unless and until the Commission determines otherwise.”6
4 Administrative Law Judge’s Ruling on Disconnection Caps and Past-due Payment Allocation, R.18-07-005 (Mar. 22, 2024); see California Community Choice Association’s Comments on Administrative Law Judge’s Ruling on Disconnection Caps and Past-due Payment Allocation, R.18-07- 005 (Apr. 19, 2024); see also California Community Choice Association’s Reply Comments on Administrative Law Judge’s Ruling on Disconnection Caps and Past-due Payment Allocation, R.18-07- 005 (May 3, 2024).
5 D.21-11-014, Decision Directing Allocation of Payment on Past-Due Bills Between Investor-Owned Utilities and Community Choice Aggregators, R.21-02-014 (Nov. 18 2021):
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M424/K116/424116557.PDF. 6 Proposed Decision, Ordering Paragraph (O¶) 1, at 12.
3 Consistent with D.21-11-014, the Proposed Decision requires the continuation of the proportional allocation to: (1) prevent the “inappropriate[] shift [of] financial risk to the CCAs, . . . [and] contribute to the financial stability of the CCAs,” because “[c]ustomers as a whole benefit from more financially stable CCAs,”7
(2) ensure equitable treatment of both bundled and
unbundled customers, (3) continue the application of D.21-11-014 as “the standard” and promote “strengthening the financial position of the CCAs [which] benefits all customers,”8 and (4)
reaffirm D.21-11-014’s finding that no statute obligates or prohibits either the waterfall or proportional allocation method. CalCCA supports and recommends adoption of the Proposed Decision, with the following modifications:
• The Commission should specify that the proportional allocation method is to be applied to all past due payments, including partial payments; and • The Commission should require the IOUs to modify their tariffs to require the proportional allocation method be used for all past due payments.

II. THE PROPOSED DECISION’S DIRECTIVES FOR THE IOUS TO CONTINUE

THE PROPORTIONAL ALLOCATION METHOD SHOULD BE ADOPTED
The Proposed Decision’s directives for the IOUs to continue the proportional allocation between the IOUs and CCAs of all customer payments, including partial payments, on past-due electric utility bills should be adopted. The Proposed Decision requires the use of the proportional allocation method because it:
• Prevents Disproportionate Allocation of Financial Risk to CCAs: The “conclusions from D.21-11-014 still hold” and “the waterfall method inappropriately shifts financial risk to the CCAs,”9 and “[t]he proportional allocation method contributes to the financial stability of the CCAs, and financially sound CCAs benefit customers as a whole”;10 7 Id., at 5.
8 Id., at 8.
9 Id., at 5.
10 Id., Findings of Fact (FoF) 3, at 11.
4 • Ensures Equitable Treatment of Bundled and Unbundled Customers:

Bundled and unbundled customers are treated equitably given: (1) both classes of customers are obligated to pay energy and distribution charges for reconnection of service, (2) the prevention of cost shifts from bundled to unbundled customers given the financial burden that the waterfall places on CCAs, and (3) the prevention of the uneven support provided by the waterfall to customers with the option to unbundle;11
• Supports the Public Interest by Ensuring Financial Viability of CCAs: The public interest is served because “strengthening the financial position of the CCAs benefits all customers” given that “CCAs are in the public interest, in that CCAs allow for a publicly-managed alternative to private utility procurement of resources;”12 and
• Furthers Legislative Intent: Relevant Public Utilities Code sections neither obligate nor prohibit the Commission from adopting either the waterfall or proportional allocation method, and the legislature has obligated use of the proportional allocation method in certain circumstances, thereby preventing the universal availability of the waterfall method and supporting adoption of the proportional allocation method.13
CalCCA supports the adoption of the Proposed Decision, with the revisions set forth below.

III. THE COMMISSION SHOULD SPECIFY THE PROPORTIONAL

ALLOCATION METHOD APPLIES TO ALL PAST DUE PAYMENTS,

INCLUDING PARTIAL PAYMENTS
While the intent of the Proposed Decision is clearly to require the proportional allocation method for partial past due payments, the language of the Proposed Decision should be clarified to incorporate this nuance. Past due payments in full are already allocated proportionally between the IOUs and CCAs according to the IOU tariffs.14 Therefore, the Commission should specify in the Proposed Decision that the proportional allocation method is now being extended to partial past due payments.
11 Id., at 5-6; FoF 4, at 11.
12 Id., at 7-8.
13 Id., at 8.
14 See PG&E Electric Rule 23, R.2; SCE Rule 23, R.2; and SDG&E Rule 27, R.2. 5 IV. THE COMMISSION SHOULD REQUIRE MODIFICATION OF THE IOUS’

TARIFFS TO REQUIRE THE PROPORTIONAL ALLOCATION FOR ALL

PAST DUE PAYMENTS
The Commission should require modification of the IOUs’ approved tariffs which allow the waterfall method. As noted in the Proposed Decision, the waterfall method is not required by statute or Commission directive but is embedded in the Commission-approved IOU tariffs.15 While the IOU tariffs explicitly allow the waterfall and the Proposed Decision indefinitely prohibits it, the Proposed Decision’s Conclusions of Law 2 states:

Approved tariffs of PG&E, SDG&E, and SCE prioritizing payments first to utility charges and second to non-utility charges are not changed by today’s decision.16
To ensure IOU compliance with the Decision and prevent customer confusion over the allocation of their partial past-due payments, the Proposed Decision should be modified to require the IOUs’ Tariffs to incorporate the proportional allocation method.

For example, PG&E’s Electric Rule 23, Section R.2 requires proportional allocation for partial payments, but Section R.3 requires the waterfall for past due partial payments. An asterisk was added during the COVID pandemic that is also currently out of date:

2. Except as provided below in Section 3, if a customer makes only a partial payment for a service account, the payment shall be allocated proportionally between PG&E’s charges and the CCA’s charges. A customer may dispute these charges . . . , but shall not otherwise have the right to direct partial payments for a particular service account.

3. In evaluating a delinquent residential Service Account for service termination and to the extent required by law or Commission regulations, partial payments shall be allocated first to delinquent disconnectable charges.* *Due to the COVID-19 pandemic and pursuant to CPUC Resolutions M-4842, M-4849 and D.21-06-036, PG&E has suspended Section R.3 of Electric Rule 23 and will allocate partial payments received from residential CCA 15 Proposed Decision, FoF 6, at 12 (“Statute neither obligates nor prohibits the Commission from adopting the proportional allocation or waterfall method”). 16 Id., COL 2, at 12.
6 customers on a pro rata basis with CCAs for up to one year, through September 30, 2021, as described in Advice 4244-G-A/5516-E-A, Advice 4388-G/6092-E and Advice 4475-G/6290-E.

Without revision, not only will PG&E’s tariff still require the waterfall method for past due partial payments, but will also cause confusion as to the outdated reference to the use of the proportional allocation method only until September 30, 2021.

SCE’s Electric Rule 23, Section R.2, also requires revision to incorporate the proportional allocation method, as it currently requires the waterfall when the customer’s account is delinquent:

2. Partial payments by customers shall be allocated on a pro rata basis to SCE charges for which delinquency may result in disconnection, and then any balance shall be prorated between the CCA and other SCE charges.

SDG&E Electric Rule 29, Section R.2 is virtually identical to SCE’s rule and also needs revision to reflect that the proportional allocation method will apply to all past due payments:

2. Partial payments by customers shall be allocated on a pro rata basis to the Utility charges for which delinquency may result in disconnection, and then any balance shall be prorated between the CCA and other Utility charges.

To ensure IOU compliance with the final decision and prevent customer confusion over the allocation of their partial past-due payments, the Proposed Decision should be modified to require the IOUs’ Tariffs to reflect the proportional allocation method. As set forth in Appendix A attached hereto, the Commission should revise Conclusion of Law (COL) 2 as follows:

2. Approved tariffs of PG&E, SDG&E, and SCE prioritizing partial payments first to utility charges and second to non-utility charges are not changed by must be revised within 30 days to incorporate today’s decision.

In addition, the Commission should add the following Ordering Paragraph:
7 2. Within 30 days of the Decision, PG&E, SDG&E, and SCE shall each file a Tier 1 Advice Letter revising their tariffs to require all past due utility payments, partial or otherwise, to be allocated between the CCA and utility on a proportional basis.

V. CONCLUSION
CalCCA appreciates the opportunity to submit these comments and requests adoption of the recommendations proposed herein. For all the foregoing reasons, the Commission should modify the Proposed Decision as provided in Appendix A.

Respectfully submitted,
Evelyn Kahl,
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
August 28, 2024
t
4 Appendix A-1

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

PROPOSED DECISION EXTENDING CURRENT PROPORTIONAL ALLOCATION

OF PAYMENT ON PAST-DUE BILLS BETWEEN INVESTOR-OWNED UTILITIES

AND COMMUNITY CHOICE AGGREGATORS

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

1. Electric utility tariffs allow the IOUs to apply partial payments on outstanding bills first to the utility charges on the bill and secondly to non-utility charges on the bill. This is known as the waterfall method.

2. D.21-11-014 of R.21-02-014, required the electric IOUs to allocate partial payments received on outstanding customer accounts proportionally between utility charges and CCA charges, regardless of customer disconnection status. This is known as the proportional allocation method.

CONCLUSIONS OF LAW

ORDERING PARAGRAPHS

1. Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company shall allocate all types of payments, including partial payments, made on past-due electric utility bills between utilities and Community Choice Appendix A-2
Aggregators based on their proportionate share of those past-due bills, regardless of the customer’s disconnection status, unless and until the Commission determines otherwise.

New Order:

2. Within 30 days of the Decision, PG&E, SDG&E, and SCE shall each file a Tier 1 Advice Letter revising their tariffs to require all past due utility payments, partial or otherwise, to be allocated between the CCA and utility on a proportional basis.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Establish
Energization Timelines.

R.24-01-018
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S OPENING

COMMENTS ON THE PROPOSED DECISION ESTABLISHING TARGET

ENERGIZATION TIME PERIODS AND PROCEDURE FOR CUSTOMERS TO

REPORT ENERGIZATION DELAYS
Evelyn Kahl,
General Counsel and Director of Policy
Leanne Bober,
Senior Counsel
Jennifer Baak,
Senior Distribution Case Manager

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
1121 L Street, Suite 400
Sacramento, CA 95814
Telephone: (510) 980-9459
E-mail: [email protected]
August 29, 2024
FILED
08/29/24
04:59 PM
R2401018
i

TABLE OF CONTENTS
I. INTRODUCTION ...............................................................................................................1 II. THE COMMISSION SHOULD ADOPT THE PROPOSED DECISION’S

IMMEDIATE ESTABLISHMENT OF STATEWIDE TARGETS AND
TIMELINES AND CONSEQUENCES FOR FAILURE TO COMPLY ...........................4 III. THE PROPOSED DECISION’S DATA REPORTING REQUIREMENTS SHOULD BE REFINED TO ENSURE INCREASED TRANSPARENCY ......................5 A. The Proposed Decision Should Be Revised to Require Section 933.5 Information for both Pending and Future Energization Requests ...........................6 B. The LSE Serving a Site/Project Should be Included in the Appendix B Data Reporting .........................................................................................................8 C. IOU Requirements for Additional Customer Site Preparation Work Should be Included in the Appendix B Reporting ...................................................9 D. The IOU Data Reports Should Be Submitted Quarterly Rather Than Only Biannually .....................................................................................................10 E. The Commission Should Clarify if Full Commission Approval is Needed to Amend the Required Data Fields in the Energization Target Reporting Template ...............................................................................................10 IV. THE PROPOSED DECISION’S APPENDIX C DRAFT CUSTOMER

ENERGIZATION DELAY COMPLAINT FORM AND PROCESSES
SHOULD BE IMPROVED ...............................................................................................11 A. The Proposed Customer Complaint Form Should Be Provided Online and Simplified for Customers ................................................................................11 B. The Commission Should Establish Public Accessible Tracking of Customer Complaints.............................................................................................12 Table of Contents continued
ii
V. THE COMMISSION SHOULD REQUIRE IOUS TO ESTABLISH

CUSTOMER ENERGIZATION DATA PORTALS IN ADDITION TO
ADOPTING THE PROPOSED DECISION’S CUSTOMER OUTREACH
REQUIREMENTS .............................................................................................................12 VI. THE COMMISSION SHOULD ESTABLISH A PHASE 2 STAKEHOLDER

WORKING GROUP IN ADDITION TO THE ANNUAL WORKSHOP
REQUIRED BY SECTION 933.5(A)(3) ...........................................................................13 VII. CONCLUSION ..................................................................................................................14

APPENDIX A

iii

TABLE OF AUTHORITIES
Statutes - California Public Utilities Code
933.5................................................................................................................................................ 6 933.5(a) .................................................................................................................................. passim 933.5(a)(2)(B) ............................................................................................................................. 5, 8 933.5(a)(3) ............................................................................................................................. passim 933.5(b) ....................................................................................................................................... 6, 7 933.5(b)(1) ...................................................................................................................................... 7 933.5(b)(2) ...................................................................................................................................... 7 933.5(d) ................................................................................................................................... 6, 7, 8 California Public Utilities Commission Rules of Practice and Procedure Rule 14.3 ......................................................................................................................................... 1 Legislation
Assembly Bill 50................................................................................................................. 2, 3, 6, 4 Senate Bill 410 ........................................................................................................................ 2, 3, 4 California Public Utilities Commission Rulings
Administrative Law Judge’s Ruling Directing Utility Responses to Questions Regarding Energization Timelines, R.24-01-018 (Mar. 21, 2024), as amended, Email Ruling Adjusting Phase 1 Schedule and Addressing the April 2, 2024, Joint Investor-Owned Utilities’ Motion, Email Ruling Adjusting Phase 1 Schedule and Addressing the April 2, 2024, Joint Investor-Owned Utilities’ Motion ......................................................................................................... 7, 8 Administrative Law Judge’s Ruling Directing Parties to Respond to Questions on Energization Issues, R.24-01-018 (June 6, 2024) ........................................................................................ 7, 8 California Public Utilities Commission Decisions
D.18-12-013 .................................................................................................................................. 10 California Public Utilities Commission Proceedings
R.24-01-018 ........................................................................................................................... passim iv

SUMMARY OF RECOMMENDATIONS
California Community Choice Association (CalCCA) recommends that the California Public Utilities Commission (Commission):
• Adopt the Proposed Decision’s immediate establishment of statewide targets for Electric Rules 15, 16, 29, 45, and main panel upgrades, and the timelines for projects requiring upstream capacity upgrades;
• Adopt the Proposed Decision’s approach to consequences for failure to comply with the targets/timelines in Phase 1, including finding an investor-owned utility (IOU) out of compliance if five percent or more of an IOU’s energization requests are overdue in one year, and monitoring compliance to assess the adoption of additional consequences in Phase 2;
• Refine the Proposed Decision’s reporting requirements to ensure increased transparency, including requiring: (1) reporting on all pending and future energization requests, (2) the identification of the load serving entity serving a site or project, (3) reporting on IOU requirements for additional customer site preparation work, (4) IOU submission of data reports on a quarterly, rather than biannual, basis to allow tracking of progress on energization projects and to quickly address delays, and (5) clarification if full Commission approval is needed, or if Commission staff is delegated authority, to amend the required data fields in the Energization Target Reporting Template; • Improve and provide online the Proposed Decision’s Appendix C customer complaint form, and establish public accessible tracking of customer complaints; • Require the IOUs to establish customer energization data portals in addition to adopting the Proposed Decision’s customer outreach requirements; and • Establish a Phase 2 stakeholder working group in addition to the annual workshop required by Public Utilities Code section 933.5(a)(3).

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Establish
Energization Timelines.

R.24-01-018
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S OPENING

COMMENTS ON THE PROPOSED DECISION ESTABLISHING TARGET

ENERGIZATION TIME PERIODS AND PROCEDURE FOR CUSTOMERS TO

REPORT ENERGIZATION DELAYS
California Community Choice Association1 (CalCCA) submits these opening comments pursuant to Rule 14.3 of the California Public Utilities Commission (Commission) Rules of Practice and Procedure2 on the Proposed Decision Establishing Target Energization Time Periods and Procedure for Customers to Report Energization Delays3 (Proposed Decision), dated August 12, 2024.

I. INTRODUCTION
The Proposed Decision is a constructive first step to improving customer energization by Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric Company (SDGE), (collectively, the IOUs), as required by Senate Bill (SB) 1 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. 2 State of California Public Utilities Commission, Rules of Practice and Procedure, California Code of Regulations Title 20, Division 1, Chapter 1 (May 2021). 3 Proposed Decision Establishing Target Energization Time Periods and Procedure for Customers to Report Energization Delays, Rulemaking (R.) 24-01-018 (Aug. 12, 2024). 2 4104 and Assembly Bill (AB) 50.5 The inability of IOUs to keep pace with customer energization requests throughout California has increased customer costs and delayed housing, municipal, commercial, and other projects. The Proposed Decision intends to: (1) accelerate energization projects through targets and timelines, (2) ensure robust IOU reporting on projects and details regarding the energization process to inform Phase 2 refinements of the targets and timelines, (3) update customer energization delay complaint procedures, and (4) improve transparency and customer outreach between the IOUs and energization customers. As noted throughout the Proposed Decision, shortcomings in the IOU data responses in Phase 1 limits the ability of the Commission to adequately address all outstanding energization issues. The robust data reporting required by the Proposed Decision is therefore intended to inform the Phase 2 refinements to the energization targets, timelines, customer complaint, and IOU engagement processes.

Community choice aggregators (CCAs) are interested in improving energization timelines and transparency on behalf of their customers and communities. CCAs provide electric generation services and other services to customers. Distribution services are provided by the IOUs, who are also responsible for interconnecting and energizing CCA customers. Many CCAs are working to accelerate building and transportation electrification in their communities to reduce dependence on fossil fuels. CCAs consistently hear concerns from customers regarding significant energization delays and other challenges with the energization process. CCAs, cities, 4 SB 410, Stats. 2023, Ch. 394. SB 410 requires the Commission to establish (1) target energization deadlines, (2) IOU annual reporting requirements on compliance with target deadlines, reasons for noncompliance, strategy for improvement, and staffing levels necessary to meet goals, and (3) reporting processes for customer complaints on energization.
5 AB 50, Stats. 2023, Ch. 317. AB 50 requires the Commission to (1) establish criteria for timely energization, (2) create IOU reporting requirements on fulfillment of timely electric service, (3) hold an annual public workshop with interested parties and experts in customer energization to discuss the IOU reports and needs for revision of the criteria, (4) evaluate the report from IOUs with backlogged projects and ensure the IOUs are taking actions necessary to energize at least 80 percent of the backlog, and (5) ensure the IOUs are improving their projected demand forecasts. 3 towns, counties, and energy, rural, business, and environmental and climate groups sent a letter to the Legislature on April 26, 2023, stating:

Severely delayed and abandoned electrical projects are a growing problem in communities throughout California. Hundreds of local projects spanning rural and urban have been delayed or cancelled, including service extensions to new affordable housing units and critical service sites ranging from hospitals to police/fire stations.

Hookups for new electric vehicle charging stations and utility-scale and customer-sited renewable energy projects are also in peril.6 As an example, the City of San Francisco recently reported 83 active projects with energization delays and increased project costs.7 Since November 2018, the City of San Francisco reports the total cost impact (additional project costs and loss of revenue) from energization delays as approximately $45 million.8 The delays impact projects at affordable housing units, libraries, the Muni, academic buildings, fire boats, recreational centers, educator housing, traffic signals and safety streetlights, and water pump stations.

SB 410 and AB 50 address these energization issues, requiring the Commission to adopt various timing and process improvements. Certain energization improvements must be adopted by September 30, 2024, including: (1) reasonable average and maximum target energization time periods, and (2) a procedure for customers to report energization delays to the Commission. This Phase 1 Proposed Decision focuses on these statutory requirements, while also increasing transparency through robust data reporting requirements for the IOUs on the energization 6 Letter from 35 Organizations Urging the California Legislature to Address the State’s Interconnection Crisis and Ensure Timely and Equitable Access to the Electrical Grid (Apr. 26, 2023) (available in Docket No. 23-IEPR-05, attachment to East Bay Community Energy Comments on May 9, 2023 Interconnection Workshop (May 24, 2023)). 7
San Francisco Public Utilities Commission Quarterly Report to the Board of Supervisors on the Status of Applications to PG&E for Electric Service (May 20, 2024), Item 15.h. on San Francisco Public Utilities Commission Regular Meeting Agenda (May 28, 2024). 8 Ibid.
4 process. Phase 2 will focus on other SB 410 and AB 50 requirements and explore improvements to the Phase 1 adopted requirements.

As described more fully below, CalCCA recommends that the Commission:
• Adopt the Proposed Decision’s immediate establishment of statewide targets for Electric Rules 15, 16, 29, 45, and main panel upgrades, and the timelines for projects requiring upstream capacity upgrades;
• Adopt the Proposed Decision’s approach to consequences for failure to comply in Phase 1, including finding an IOU out of compliance if five percent or more of an IOU’s energization requests are overdue in one year, and monitoring compliance to assess the adoption of additional consequences in Phase 2; • Refine the Proposed Decision’s reporting requirements to ensure increased transparency, including requiring: (1) reporting on all pending and future energization requests, (2) the identification of the load serving entity (LSE) serving a site or project, (3) reporting on IOU requirements for additional customer site preparation work, (4) IOU submission of data reports on a quarterly, rather than biannual, basis to allow tracking of progress on energization projects and to quickly address delays, and (5) clarification if full Commission approval is needed, or if Commission staff is delegated authority, to amend the required data fields in the Energization Target Reporting Template;
• Improve and provide online the Proposed Decision’s Appendix C customer complaint form, and establish public accessible tracking of customer complaints; • Require the IOUs to establish customer energization data portals in addition to adopting the Proposed Decision’s customer outreach requirements; and • Establish a Phase 2 stakeholder working group in addition to the annual workshop required by Public Utilities Code section 933.5(a)(3).9 II. THE COMMISSION SHOULD ADOPT THE PROPOSED DECISION’S

IMMEDIATE ESTABLISHMENT OF STATEWIDE TARGETS AND

TIMELINES AND CONSEQUENCES FOR FAILURE TO COMPLY
The Commission should adopt the Proposed Decision’s standardized, statewide energization metrics for steps within the IOUs’ control: (1) average and maximum day targets for Electric Rules 15, 16, 29, and 45, and main panel upgrades, and (2) the more flexible and 9 All subsequent code sections cited herein are references to the California Public Utilities Code unless otherwise specified.
5 project specific timelines for projects requiring upstream capacity upgrades. CalCCA supports the Commission’s plan to take this preliminary step in Phase 1 to accelerate IOU energization.

The overall lack of consistency and granularity in the IOUs’ responses to the data requests in Phase 1 necessitate further exploration of the root causes of energization delays, both within and outside of the IOUs’ control. Based on both the IOUs’ ability to meet the targets, and the additional data provided by the IOUs on upstream capacity upgrade timelines, the Commission can further refine these statewide targets in Phase 2.

The Proposed Decision also takes a first step towards imposing consequences on the IOUs for failure to meet the targets, which will result in the project being deemed “overdue.”10 An IOU with five percent or more of customer energization requests overdue in one year will “be out of compliance with the Commission’s directive.”11 While these Phase 1 consequences lack any penalties for noncompliance, CalCCA agrees with the Commission’s approach to first establish these targets and closely monitor through robust data collection whether energization delays are lessened. For the timelines on upstream capacity upgrades, the additional data can lead to the establishment of targets subject to the same consequences. If the IOUs fail to comply with these Phase 1 requirements, the Commission can consider additional compliance requirements and consequences after gathering additional data to better understand the factors leading to delays.

III. THE PROPOSED DECISION’S DATA REPORTING REQUIREMENTS

SHOULD BE REFINED TO ENSURE INCREASED TRANSPARENCY
The data requirements adopted in the Proposed Decision should be refined to ensure increased transparency into the causes of energization delays. The Proposed Decision requires the IOUs to jointly develop a data reporting template that aligns with section 933.5(a)(2)(B), the 10 Proposed Decision, at 65.
11 Ibid.
6 new energization targets/timelines, and the “Energization Target Reporting Template Requirements” set forth in the Proposed Decision, Appendix B. As described below, the Commission should require: (1) incorporation into Appendix B of section 933.5 reporting requirements for both pending and future energization requests, (2) identification in the Appendix B data reporting of the LSE serving a particular site or project, (3) reporting on IOU requirements for additional customer site preparation work, (4) IOU submission of data reports on a quarterly, rather than biannual, basis to allow the Commission, customers, and LSEs to track progress on energization projects and to quickly address delays, and (5) clarification if full Commission approval is needed, or if Commission staff is delegated authority, to amend the required data fields in the Energization Target Reporting Template.

A. The Proposed Decision Should Be Revised to Require Section 933.5 Information for both Pending and Future Energization Requests The Proposed Decision should be revised to ensure all data relevant to the creation and refinement of the criteria for timely energization is considered, as required by AB 50, and codified in section 933.5. The Proposed Decision currently omits relevant data describing pending energization requests from December 2023 to the date of adoption of the Proposed Decision. Section 933.5 requires the Commission to collect and analyze three overall categories of IOU data:
1) Pre-Phase 1 Decision Data – Section 933.5(d): Information collected annually by the Commission in the form of a report “to inform the Commission’s determination of criteria for timely service,” with this requirement becoming inoperative once the Commission establishes reporting requirements pursuant to section 933.5(a);
2) Post-Phase 1 Decision Data – Section 933.5(a): Information collected pursuant to the criteria and reporting requirements established by the Commission pursuant to section 933.5(a); and
--
7 3) Energization Backlog Data – Section 933.5(b): If an IOU had, as of January 31, 2023, energized less than 35 percent of customers with completed applications 12 months or older, that IOU must submit a report by December 1, 2024, demonstrating that 80 percent of customers with completed applications as of January 31, 2023, are energized (and if the IOU does not meet the 80 percent metric, the report must include specific information required by section 933.5(b)(2)).

Rulings dated March 21, 2024,
12 and June 6, 2024,13 required the IOUs to provide a
portion of the Pre-Phase 1 Decision Data required by section 933.5(d) for the January 2019 to December 2023 period. However, no additional Ruling or data request has been issued for the post-December 2023 period. The backlog reporting required by section 933.5(b) does require certain ongoing data on projects with completed applications as of January 31, 2023, but the data required is not as extensive as the section 933.5(d) data.14 The Proposed Decision explicitly adopts new reporting requirements (i.e., the biannual reports with the Appendix B data) pursuant to section 933.5(a) for energization projects that have 12 Administrative Law Judge’s Ruling Directing Utility Responses to Questions Regarding Energization Timelines, R.24-01-018 (Mar. 21, 2024), as amended, Email Ruling Adjusting Phase 1 Schedule and Addressing the April 2, 2024, Joint Investor-Owned Utilities’ Motion, Email Ruling Adjusting Phase 1 Schedule and Addressing the April 2, 2024, Joint Investor-Owned Utilities’ Motion. 13 Administrative Law Judge’s Ruling Directing Parties to Respond to Questions on Energization Issues, R.24-01-018 (June 6, 2024).
14 The section 933.5(b) data is required when the IOU energized less than 35 percent of customers, with applications 12 months or older. See Pub. Util. Code § 933.5(b)(1). In that case, the IOU is required to report on whether energization of 80 percent of projects is complete by December 1, 2024. Ibid. This section 933.5(b) data will therefore not provide information on the 20 percent of projects not energized if the IOU meets the 80 percent threshold. In addition, if the IOU had energized more than 35 percent by January 31, 2023, no section 933.5(b) data is required. Finally, the 2024 data required by section 933.5(b) is different from the section 933.5(d) data. See id., § 933.5(b) (requiring data the IOU to “implement actions necessary to meet the [80%] performance metric and include a summary of these actions in the report submitted to the commission” including number of withdrawn or cancelled applications, aggregated data on the reasons for withdrawal or cancellation, and factors leading to delays outside the IOU’s control); see also id., § 933.5(d) (requiring number of submitted, completed, pending and uncompleted requests for energization, time for energization, spending on energization, and other information requested by the commission to evaluate energization). 8 submitted complete applications beginning on the issuance date of the adopted Decision.15 In other words, the new data will only include data on projects that submit applications on or after the date of the adopted Decision.

The already obtained data, and the new data the IOUs are required to provide to the Commission will therefore be missing a crucial piece – section 933.5(d) data for projects post-December 2023 and before the Decision is adopted. The Proposed Decision already correctly notes that much of the data provided by the IOUs in response to the ALJ Rulings lacks the consistency or granularity needed for the Commission to adequately set targets and timelines.16 To thoroughly evaluate the IOU energization processes, CalCCA recommends that any missing section 933.5(d) data from December 2023 through the adoption date of the Decision be added to the list of required Appendix B data.

B. The LSE Serving a Site/Project Should be Included in the Appendix B Data Reporting
Appendix B should be revised to require the identification of LSEs, including CCAs, when data is being collected on a specific site or project. LSEs need to be informed about energization delays that directly affect their customers, impact customer programs, and in some cases, impact the energization of assets under their control or ownership. Many CCAs have launched or are considering programs to encourage the use of electric vehicles (EV), smart 15 See Proposed Decision, Ordering Paragraph (O¶) 18, at 84 (“The biannual energization reports required in [OP] 17 must reflect data for all customer energization requests submitted after the issuance of this decision and will be posted on the Commission’s Energization website . . . .” (emphasis added); id. at 49 (“The large electric IOUs shall provide data related to all energization projects that have submitted complete applications beginning on the issuance date of this decision in their first biannual report filed no later than March 31, 2025.”) (emphasis added); id. at 65 (“Compliance reports shall be filed by the IOUs every six months to the R.24-01-018 service list, with the first submission required to be served no later than March 31, 2025, and the second no later than September 30, 2025”). 16 Id. at 47 (“information provided by the large electric IOUs to date is inadequate to support full implementation of Pub. Util. Code § 933.5(a)(2)(B). While the large electric IOUs collected some of the data necessary to evaluate timeliness of customer energization requests, there are many gaps that must be addressed to ensure statutory compliance”).
9 appliances, or solar plus storage, and to facilitate participation in managed EV charging, load shifting, demand response, and other beneficial programs. These programs can provide resiliency, reduce customer bills, achieve green-house gas reduction goals, and lower power procurement costs. Project delays such as installing panel upgrades or energizing public EV charging stations, however, may discourage customer participation in these programs and could have negative financial implications for CCAs and their customers. The significant energization delays have already increased the burden on CCA customer support resources, given the lack of data and communication about these delays and who is responsible for addressing them. CalCCA therefore recommends that Appendix B be amended to require identification of the LSE serving the customer when data is being collected on a site/project basis. Any summary data should also include both IOU and LSE information, to the extent possible and applicable.17 C. IOU Requirements for Additional Customer Site Preparation Work Should be Included in the Appendix B Reporting
Appendix B should be revised to require the IOUs to describe when and why an IOU requires a customer to do site preparation in addition to what was originally planned before the IOU completes electrical construction. This might occur, for example, if conditions on the distribution grid change between the IOU’s initial project design (Step 2) and the preconstruction field meeting (Step 5), if additional site improvements are identified during the electrical construction (Step 6), or if an IOU makes an error during the project design step. In such instances, the delay might be categorized as work outside the IOU’s control. To ensure accurate reporting and to facilitate improvements in energization timeliness, however, the IOUs should be 17 For example, the Proposed Decision, Appendix B, Items 10-16, require the IOUs to provide general data on total numbers of energization requests received, approved, and completed, in aggregate and broken down by end-use. The IOUs should be required to identify which of the energization requests are for customers of LSEs other than the IOUs.
10 required to report such data, with an explanation of why and when in the process the additional work was required.

D. The IOU Data Reports Should Be Submitted Quarterly Rather Than Only Biannually
The IOUs should be required to submit their energization data reports more frequently than the Proposed Decision’s biannual requirement.
18 At a minimum, quarterly reports will allow
the Commission, customers, and LSEs to track progress on specific energization projects and quickly address delays. In fact, in other proceedings addressing urgent situations, the Commission has required monthly reporting. For example, to track rising arrearages and potential disconnections of customers, the Commission in the Disconnections proceeding required the IOUs to provide monthly disconnections reports.19 Here, at least quarterly reporting is necessary given the magnitude of the energization backlogs, the significant delays being experienced by customers, and the urgency of accelerating energization times to support the anticipated electric load growth needed to achieve the State’s carbon reduction goals.

E. The Commission Should Clarify if Full Commission Approval is Needed to Amend the Required Data Fields in the Energization Target Reporting Template
The Commission should clarify conflicting statements in the Proposed Decision as to whether full Commission approval is required, or if Energy Division staff has been delegated authority, to amend the Energization Target Reporting Template. Section 10 of the Proposed Decision, and Ordering Paragraphs 8 and 16, delegate authority to Commission staff to modify the Energization Target Reporting Template.20 Conclusion of Law 9, however, states that 18 Id., O¶s 17 and 18, at 83-84.
19 D.18-12-013, Decision Adopting Interim Rules to Reduce Residential Customer Disconnections for California-Jurisdictional Energy Utilities, R.18-07-005 (Dec. 13, 2018), O¶ 6, at 31. 20 Proposed Decision, at 51.
11 “(a)mendments to the required data fields adopted in Appendix B of this decision, Energization Target Reporting Template Requirements, will require full Commission approval.”21 These conflicting provisions should be clarified in the final decision.

IV. THE PROPOSED DECISION’S APPENDIX C DRAFT CUSTOMER

ENERGIZATION DELAY COMPLAINT FORM AND PROCESSES SHOULD BE

IMPROVED
A. The Proposed Customer Complaint Form Should Be Provided Online and Simplified for Customers
The Appendix C Customer Energization Complaint Form should be revised to ensure ease of customer use and Commission analysis of the information. First, in addition to allowing a customer to email and mail their complaint with the information required on the form, the Commission should allow the form to be completed online. The online form should have separate fields for each category of data for which the Commission requires a response. The option to fill out and submit the form through an online webpage will make it easier for customers to submit their complaints.

Second, the form assumes customers are familiar with electric tariff rules and understand electric utility jargon, which may be true for developers, contractors, and customers accustomed to working with electric utilities, but may intimidate other customers. Therefore, the form should include further explanatory information regarding the type of projects for which each tariff rule applies. This explanatory information should be provided to customers seeking to file complaints in two formats: (1) clear definitions and explanations of industry terms and requirements in the form itself, and (2) an attached “Frequently Asked Questions” (FAQ) document which clearly explains issues and terms in the form. The FAQ document can provide resources such as hyperlinks and where to find additional relevant information. 21 Id., Conclusion of Law (COL) 9, at 76.
12 Finally, even with a simplified online form, customers who face language, access, or other barriers may need assistance completing and submitting the form. At a minimum, the form should be available in multiple languages. Customers should also be allowed to designate a local agency, such as a CCA, Community Based Organization (CBO), or other third-party to complete and submit a complaint on their behalf.22
B. The Commission Should Establish Public Accessible Tracking of Customer Complaints
The Commission should establish a public tracking mechanism for submitted complaints.

The Proposed Decision states that Commission staff “does not have the bandwidth to respond to each customer delay complaint on a case-by-case basis, [but that] these collective reports will help identify trends in energization delays, such as the impact geographical locations have on the energization timing.”23 While CalCCA recommends that each customer complaint be individually addressed, if that cannot be achieved the Commission should at least ensure transparency regarding the status of a customer complaint by establishing a public tracking mechanism with anonymized customer information (allowing individual customers to identify their own project). Without a means of checking on status, customers may surmise their complaints are being ignored or may decide not to file a complaint at all.

V. THE COMMISSION SHOULD REQUIRE IOUS TO ESTABLISH CUSTOMER

ENERGIZATION DATA PORTALS IN ADDITION TO ADOPTING THE
PROPOSED DECISION’S CUSTOMER OUTREACH REQUIREMENTS
The Proposed Decision’s detailed requirements for improved customer outreach and transparency from the IOU account/project manager should be adopted.24 The IOUs that have 22 See California Community Choice Association’s Comments on the Administrative Law Judge’s Ruling Directing Parties to Respond to Questions on Energization Issues, R.24-01-018 (June 18, 2024), at 7.
23 Proposed Decision, at 65.
24 Id. at 53.
13 not already done so should also be required to create customer energization data portals to enable increased communications and transparency. The Proposed Decision requires the IOUs’ “customer-engagement and communication plan” submitted by Tier 1 Advice Letter within 60 days of issuance of the Decision to include a “tool” to notify customers of completion of steps in the energization process.25 CalCCA recommends the Commission require an automated system or data portal to, at a minimum, display project tracking and allow communications between the customer and account/project manager, similar to the Builder Portal described by SDG&E at the February 2, 2024 Workshop.26 Such a portal can efficiently provide the services required by the tool along with other customer outreach functions described in the Proposed Decision.

Accordingly, in addition to adopting the Proposed Decision’s customer outreach requirements, the Commission should require the IOUs that have not already done so to establish customer energization data portals.

VI. THE COMMISSION SHOULD ESTABLISH A PHASE 2 STAKEHOLDER

WORKING GROUP IN ADDITION TO THE ANNUAL WORKSHOP
REQUIRED BY SECTION 933.5(A)(3)
The Commission should immediately establish a Phase 2 working group to allow Energy Division and stakeholder involvement in the formulation of the Energization Target Reporting Template, as well as ongoing Phase 2 issues. Ordering Paragraph 11 states that “the large electric IOUs shall incorporate any comments from the Commission’s Energy Division and parties to this proceeding to refine the template as needed.”27 Rather than wait for parties to comment on a 25 Id. at 58.
26 See SDGE Presentation of Energization Timeline Workshop, Panel 1, Eric Turner, Project Manager – Developer Initiation (Feb. 2, 2024) (describing functions of the SDGE “Builder Portal” including an online application, project tracking, project checklists, and standards videos), located at:
www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/infrastructure/energization/ab50_sb410-energization-workshop_02022024.pdf. 27 Proposed Decision, O¶ 11, at 82. 14 Tier 1 Advice Letter to be filed 60 days after the issuance of the Decision, the IOUs, Energy Division, and stakeholders can reach consensus on the template during a working group process.

As recommended by CalCCA and many parties in this proceeding, inclusion of stakeholders in a working group will allow industry groups, LSEs, developers, and others to weigh in on quickly improving the energization process, rather than waiting for the annual workshop required by section 933.5(A)(3) and other formal Commission proceedings and comment periods.28 CalCCA therefore recommends the immediate establishment of a working group to meet on a regular basis to inform the Phase 2 proceedings.

VII. CONCLUSION
CalCCA appreciates the opportunity to submit these opening comments and requests adoption of the recommendations proposed herein. For all the foregoing reasons, the Commission should modify the Proposed Decision as provided in Appendix A.

Respectfully submitted,
Evelyn Kahl,
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
August 29, 2024
28 See California Community Choice Association’s Status Conference Statement, R.24-01-018 (May 20, 2024), at 3-4 (recommending formation of working group); Opening Comments of the Alliance for Automotive Innovation on Scoping Memo, R.24-01-018 (May 3, 2024), at 10 (recommending convening a quarterly working group to “identify bottlenecks and pain points, share information and best practices, and develop solutions to improves energization processes”); see also Opening Comments of the Interstate Renewable Energy Council, Inc. on the Commissioner’s Scoping Memo and Ruling, R.24-01-018 (May 3, 2024); Reply Comments of the Interstate Renewable Energy Council, Inc. on the Commissioner’s Scoping Memo and Ruling, R.24-01-018 (May 17, 2024); Opening Comments of Environmental Defense Fund and Natural Resources Defense Council on Scoping Memo, R.24-01-018 (May 3, 2024). t Appendix A-1

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

THE PROPOSED DECISION ESTABLISHING TARGET ENERGIZATION TIME

PERIODS AND PROCEDURE FOR CUSTOMERS TO REPORT ENERGIZATION DELAYS

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 underlined1

FINDINGS OF FACT

4.29 The data collected through the requirements adopted in Section 10 of this decision, BiannualQuarterly Energization Reporting Requirements can improve the Commission’s ability to identify the appropriate amount of future acceleration of the large electric IOUs’ energization target(s) in Phase 2 of this proceeding.

21. The data collected pursuant to Section 10 of this proceeding, BiannualQuarterly Energization Reporting Requirements, will include specific information about energization requests within ESJ communities to inform whether additional data should be collected for specific communities.

32. Consistent with Pub. Util. Code § 933.5(2)(B) it is reasonable to direct the large electric IOUs to develop a data reporting template consistent with the steps outlined in Section 10 of this decision, BiannualQuarterly Energization Reporting Requirements, and Appendix B of this decision, Energization Target Reporting Template Requirements.

33. Public comments can improve the biannualquarterly data reporting template as required in in Section 10 of this decision, BiannualQuarterly Energization Reporting 29 The Proposed Decision omitted numbering of the Findings of Fact. CalCCA is providing numbers based on the ordering of the Findings of Fact included in the Proposed Decision for convenience.

Appendix A-2
Requirements, and Appendix B of this decision, Energization Target Reporting Template Requirements. Public comments may identify potential revisions to the proposed data reporting template before the large electric IOUs’ initial biannualquarterly energization reports are filed.

CONCLUSIONS OF LAW

5. The energization target reporting template directed in Section 10 of this decision, BiannualQuarterly Energization Reporting Requirements, can incorporate party feedback before the large electric IOUs file their first biannual quarterlyenergization reports.

6. To comply with Pub. Util. Code § 933.5(a)(3), the large electric IOUs should host a public workshop within 90 days of submitting their initial biannualquarterly data, due March 31, 2025, to the Commission.

ORDERING PARAGRAPHS

4. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company must comply with the data reporting requirements set forth in Section 10, BiannualQuarterly Energization Reporting Requirements, and Appendix B, Energization Target Reporting Template Requirements, as adopted in this decision.

5. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company must submit a Tier 1 Advice Letter no later than 60 days after the issuance of this decision that proposes a consolidated reporting template to track the data requirements listed in Section 10, BiannualQuarterly Energization Reporting Requirements, and Appendix B, Energization Target Reporting Template Requirements, as adopted in this decision.

9. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall ensure the data collection template proposed pursuant to Section 10 of this decision, BiannualQuarterly Energization Reporting Requirements, and Appendix A-3
Appendix B of this decision, Energization Target Reporting Template Requirements, aligns with the goals of the Commission’s Environmental and Social Justice Action Plan.

10. The proposed data collection template directed in Section 10 of this decision, BiannualQuarterly Energization Reporting Requirements, and Appendix B of this decision, Energization Target Reporting Requirements, shall provide clear descriptions of the strategies Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company (the large electric investor-owned utilities (IOU)) will employ to engage local and tribal governments to ensure their energization processes are clear to all customers.

11. Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company (the large electric investor-owned utilities (IOU)) must jointly file and serve the proposed data template, as required in Section 10 of this decision, BiannualQuarterly Energization Reporting Requirements, via a Tier 1 Advice Letter on the service list for Rulemaking (R.) 24-01-018 no later than 60 days after the issuance of this decision. The large electric IOUs shall incorporate any comments from the Commission’s Energy Division and parties to this proceeding to refine the template as needed. The reporting template shall include the full list of data required to be collected as provided in Appendix B, Energization Target Reporting Template Requirements. The large electric IOUs must submit the final template with recorded data in their first annual Tier 1 Advice Letter no later than March 31, 2025.

12. Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company shall provide information about energization projects that trigger, are delayed by, or are cancelled due to an identified upstream capacity upgrade in their Appendix A-4
biannualquarterly reports filed pursuant to Section 10 of this decision, BiannualQuarterly Energization Reporting Requirements.

16. The California Public Utilities Commission’s Energy Division is authorized to make any necessary updates to the biannualquarterly energization target reporting template upon review of the initial reports from Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company, if staff determines that changes are necessary to improve data collection prior to the next decision in this proceeding.

17. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall each file and serve biannualquarterly energization reports to the California Public Utilities Commission every sixthree months to demonstrate compliance with the statewide targets outlined in Section 7, Energization Targets, of this decision, with the first biannualquarterly energization data report filed and served to the service list of Rulemaking 24-01-018 by March 31, 2025, and the second by September 30, 2025.

18. The biannualquarterly energization reports required in Ordering Paragraph 17 must reflect data for all customer energization requests submitted after the issuance of this decision and will be posted on the Commission’s Energization website, for the purposes of improving Commission, customer, and party insight into energization delays occurring in the large electric investor-owned utility service territories.

NEW CONCLUSIONS OF LAW
X. Creating an online customer complaint form and establishing publicly accessible tracking of customer complaints will improve transparency and meet requirements established in AB 50 and SB 410.

Appendix A-5
X. IOU data portals will provide greater transparency for customers to track energization progress and fulfill the customer notification requirements established in Section 12 of this decision, Improved Customer Outreach.

X. A working group process will facilitate stakeholder input in the formulation of the Energization Target Reporting Template, as well as ongoing Phase 2 issues.

NEW ORDERING PARAGRAPHS
X. The California Public Utilities Commission’s Energy Division shall establish an online Customer Complaint Form consistent with the requirements outlined in Section 11, Customer Reporting Procedures, and Appendix C, Draft Customer Complaint Form, as adopted in this decision. Energy Division shall establish publicly accessible tracking of customer complaints using data collected from this online Customer Complaint Form.

X. The large IOUs that have not already done so shall each establish customer energization data portals as part of their customer-engagement and communication plan.

These data portals shall fulfill the customer notification requirement described in Section 12, Improved Customer Outreach, as adopted in this decision.

X. The California Public Utilities Commission’s Energy Division shall establish a working group process to allow Energy Division and stakeholder involvement in the formulation of the Energization Target Reporting Template, as well as ongoing Phase 2 issues. The first meeting of this working group shall take place no later than 30 days after the issuance of this decision.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue
Electric Integrated Resource Planning and
Related Procurement Processes.

R.20-05-003
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S OPENING COMMENTS

ON THE PROPOSED DECISION ALLOWING BRIDGE RESOURCES FOR

ALTERNATIVE COMPLIANCE WITH DIABLO CANYON REPLACEMENT
RESOURCE CATEGORY IN DECISION 21-06-035
Evelyn Kahl,
General Counsel and Director of Policy
Lauren Carr,
Senior Market Policy Analyst
Eric Little,
Director of Regulatory Affairs

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
1121 L Street, Suite 400
Sacramento, CA 95814
Telephone: (510) 980-9459
E-mail: [email protected]
August 29, 2024
FILED
08/29/24
11:26 AM
R2005003
i

TABLE OF CONTENTS
I. INTRODUCTION ...............................................................................................................2 II. THE COMMISSION SHOULD ADOPT THE PROPOSED DECISION ..........................3 III. CONCLUSION ....................................................................................................................5 ii

TABLE OF AUTHORITIES
California Public Utilities Commission Decisions
D.21-06-035 ............................................................................................................................ 2, 4, 5 D.24-02-047 .................................................................................................................................... 4 California Public Utilities Commission Proceedings
R.20-05-003 ........................................................................................................................... passim California Public Utilities Commission Rules of Practice and Procedure Rule 14.3 ......................................................................................................................................... 1 California Public Utilities Commission Rulings
Administrative Law Judge’s Ruling Seeking Comments on Staff Proposal to Allow Temporary Bridge Resources to Meet Diablo Canyon Replacement Obligations, R.20-05-003 (May 21, 2024) ........................................................................................................................................... 2 iii

SUMMARY OF RECOMMENDATIONS
• The Proposed Decision provides a well-balanced solution that supports system reliability and ratepayer cost savings while carefully addressing the current realities of the procurement of new resources, in which project delays can happen that threaten load-serving entity compliance despite their best efforts to comply. The California Public Utilities Commission should adopt the Proposed Decision. 1 BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue
Electric Integrated Resource Planning and
Related Procurement Processes.

R.20-05-003
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S OPENING COMMENTS

ON THE PROPOSED DECISION ALLOWING BRIDGE RESOURCES FOR

ALTERNATIVE COMPLIANCE WITH DIABLO CANYON REPLACEMENT
RESOURCE CATEGORY IN DECISION 21-06-035
The California Community Choice Association (CalCCA)1 submits these opening comments pursuant to Rule 14.3 of the California Public Utilities Commission (Commission) Rules of Practice and Procedure2 on the proposed Decision Allowing Bridge Resources for Alternative Compliance With Diablo Canyon Replacement Resource Category in Decision 21- 06-0353(Proposed Decision), dated August 9, 2024.
1 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. 2 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. 3 Proposed Decision Allowing Bridge Resources for Alternative Compliance With Diablo Canyon Replacement Resource Category in Decision 21-06-035, Rulemaking (R.) 20-05-003 (Aug. 9, 2024):
http://docs.cpuc.ca.gov/SearchRes.aspx?DocFormat=ALL&DocID=537639351. 2 This decision allows load-serving entities (LSEs) with compliance obligations in Decision (D.) 21-06-0354 as part of the category of resources designed to replace the attributes of the Diablo Canyon Power Plant (DCPP), to use short-term alternative compliance options as defined in the Proposed Decision.

I. INTRODUCTION
CalCCA applauds the Commission for developing creative compliance options that will support reliability and affordability objectives while recognizing procurement realities that make it difficult to predict delays and bring all resources online on schedule despite reasonable efforts.

Considering the “very challenging procurement environment” in which “LSEs were not likely to meet their requirements for Diablo Canyon replacement resources in time” for the June 1, 2025, compliance deadline,5 the Proposed Decision approves the option for LSEs to use bridge capacity resources for no more than three years to count towards the requirements. The Proposed Decision finds that allowing bridge capacity to meet the DCPP replacement requirement has the potential for ratepayer cost savings and short-term reliability benefits.6 CalCCA did not take a position on the staff proposal7 because system reliability and affordability impacts will depend on (1) the unique position of LSEs and their DCPP replacement resources procurement progress, and (2) the proposal’s impact on the Resource 4 D.21-06-035, Decision Requiring Procurement to Address Mid-Term Reliability (2023-2026), R.20-05-003 (June 24, 2021):
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M389/K603/389603637.PDF. 5 Proposed Decision at 3.
6 Conclusion of Law (COL) 1 and COL 2.
7 Administrative Law Judge’s Ruling Seeking Comments on Staff Proposal to Allow Temporary Bridge Resources to Meet Diablo Canyon Replacement Obligations, R.20-05-003 (May 21, 2024):
https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M532/K042/532042838.PDF. 3 Adequacy (RA) market, which is currently facing significant scarcity. 8 However, CalCCA
supports the Commission in taking creative steps to allow alternative ways to comply with requirements that could be very difficult to achieve in the current market. Issues causing project delays, such as supply chain, permitting, and interconnection, have not been resolved and could continue to impact development timelines unexpectedly or without time for replacement. For these reasons, CalCCA recommends the Commission adopt the Proposed Decision.

II. THE COMMISSION SHOULD ADOPT THE PROPOSED DECISION
The Proposed Decision reflects the Commission’s efforts to craft a well-balanced solution that carefully addresses the current realities of the market for new resources, in which project delays can happen that threaten LSE compliance despite their best efforts to comply. Community choice aggregators (CCA) understand the urgent need to bring new resources online to increase capacity on the grid, alleviate current constraints on the RA market, and support the transition to clean electricity, and have signed over 16 gigawatts of long-term contracts for clean resources. At the same time, all LSEs and developers face risks in getting new capacity online as scheduled, including interconnection delays, supply chain issues, permitting challenges, and others.

CalCCA supports the Proposed Decision’s recognition that:

In the event of an unexpected last-minute delay to a Diablo Canyon replacement resource coming online, the LSE may be unable to act quickly enough to substitute a bridge resources... we emphasize that Commission staff will assess an LSE’s compliance status holistically, considering all of the LSE’s efforts to procure resources and taking last-minute delay notices from developers into account.9

8 California Community Choice Association’s Reply Comments on Administrative Law Judge’s Ruling Seeking Comments on Staff Proposal to Allow Temporary Bridge Resources to Meet Diablo Canyon Replacement Obligations, R.20-05-003 (June 21, 2024), at 2:
https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M534/K357/534357081.PDF. 9 Proposed Decision at 16.
4 The optionality provided by the Proposed Decision and the commitment to reviewing LSE procurement efforts when assessing compliance is necessary in circumstances where it is not possible for all LSEs to comply with their procurement obligations due to factors outside of their control despite reasonable efforts. For these reasons, the Commission should adopt the Proposed Decision and continue to find creative ways across its proceedings to provide such optionality and review compliance status based on a holistic review of LSE efforts when warranted.

The Proposed Decision finds that “[b]ased on reliability analysis and production cost modeling conducted by Commission staff to inform various decisions, including the PSP portfolio adopted in D.24-02-047,10 2025 is expected to be a tight year from an electric reliability perspective, even with Diablo Canyon still online.”11 CalCCA agrees with this finding and highlights that using bridge capacity to meet DCPP replacement requirements in this interim period may exacerbate the already tight RA market, which has resulted in procurement challenges and extremely high prices.12 However, the Proposed Decision also finds that “many LSEs have represented that complying with the Diablo Canyon replacement category of resources in D.21-06-035 has been difficult and could be expensive.”13 By offering flexibility in the ways LSEs can comply with their obligations, the Commission recognizes the negative ratepayer impact of rigid compliance obligations that do not consider procurement realities. The Proposed Decision strikes a reasonable balance, given the realities of the RA and IRP 10 D.24-02-047, Decision Adopting 2023 Preferred System Plan and Related Matters, and Addressing Two Petitions for Modification, R.20-05-003 (Feb. 15, 2024):
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M525/K918/525918033.PDF. 11 Finding of Fact (FOF) 2. 12 California’s Constrained Resource Adequacy Market: Ratepayers Left Standing in a Game of Musical Chairs (Updated Jan. 16, 2024): https://cal-cca.org/wp-content/uploads/2024/02/CalCCA-Stack-Analysis-2023-2026-updated-01_16_24-.pdf. 13 FOF 4. 5 compliance programs, by introducing the bridge capacity option and maintaining eventual compliance with D.21-06-035 with new resources.

III. CONCLUSION
CalCCA appreciates the opportunity to submit these opening comments on the Proposed Decision, which allows for compliance optionality while accounting for reliability needs and ratepayer impacts. For these reasons, CalCCA respectfully requests the adoption of the Proposed Decision.

Respectfully submitted,
Evelyn Kahl,
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
August 29, 2024
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METRICS
Data Category Metric Definition Format/Display Cadence DAC-GT CSGT ECR Modified GT CREP Program - Capacity
Program Cap
Maximum number of MWs designated for program Number N/A X X X X X Program - Cost Annual program costs Total program costs for the year based on actuals Number Annually X X X X X Program - Projects Projects procured (aka "Projects approved") Total number of executed project PPAs approved by the Commission Number Quarterly X X X X X Program - Capacity MWs procured MWs procured, defined as PPAs approved by the Commission Number Quarterly X X X X X Program - Projects Projects online (aka "Projects completed") Total number of dedicated projects online Number Quarterly X X X X X Program - Capacity MWs online Dedicated MWs online Number Quarterly X X X X X Program - Capacity Annual program generation Total generation of all online projects combined in MWh Number Annually X X X X X Program - Capacity
Annual Unsubscribed MWh
Number of unsubscribed MWhs, derived from total program generation minus participant usage/ RECs retired Number Annually X X X X TBD Program - RECs Annual MWh of Participant Usage Total number of MWhs served to participants Number Annually X X X X X Program - RECs
Annual MWh of RPS/interim RECs retired for
participants
Total number of RPS RECs in MWhs that come from interim resources retired to serve participants Number Annually X X - X TBD
Program - RECs
Annual MWh of Programmatic/dedicated RECs
retired for participants
Total number of Programmatic RECs in MWhs that come from dedicated resources retired to serve participants Number Annually X X X X TBD Program - Subscriber
Number of customers enrolled
Total number of customers (service agreements) currently enrolled in the program Number Quarterly X X X X X
Program - Subscriber MWs Enrolled Number of MWs enrolled in program Number Quarterly X X X X X Program - Subscriber
Number of low-income customers enrolled Total number of customers enrolled in low-income customer programs (e.g., CARE/FERA) Number Quarterly X X - - X
Program - Subscriber
Number of new low-income customers enrolled in
CARE/FERA at the time of program enrollment
Number of new low-income customer enrollments in CARE or FERA in the process of enrolling in the program Number Quarterly - X - - - Program - Subscriber
Average customer monthly discount
Average monthly bill discount provided to customers based on actuals Number Annually X X - - X Program - Subscriber
CSGT master-metered accounts The total number of master-metered accounts participating in the CSGT Program Number Quarterly - X - - -
Program - Subscriber
CSGT master-metered capacity The total capacity, in MWs, allocated to master-metered accounts participating in the CSGT Program Number Quarterly - X - - -
FIELDS
All metrics should be displayed on the DG Stats website at the program level by LSE. The end user may have the option to aggregate and view the program metrics by service territory, LSE, or any other groupings deemed appropriate in design meetings. Upon more in depth discussion with the PAs, the vendor and E.D. the PAs submit that the information below may change in order to best serve the reporting needs of the program. # Internal
FIELDS
Data Category Field Definition Format/Display Cadence DAC-GT CSGT ECR Modified GT CREP Source Notes Program - Cost Annual program costs Total program costs for the year based on actuals Number Annually X X X X X suggested by ED Program - RECs Annual MWh of Participant Usage Total number of MWhs served to participants Number Annually X X X X X D.24-05-065 pp.129-130 Program - RECs
Annual MWh of RPS/interim RECs retired for
participants
Total number of RPS RECs in MWhs that come from interim resources retired to serve participants Number Annually X X - X TBD D.24-05-065 pp.129-130 Program - RECs
Annual MWh of Programmatic/dedicated RECs
retired for participants
Total number of Programmatic RECs in MWhs that come from dedicated resources retired to serve participants Number Annually X X X X TBD D.24-05-065 pp.129-130 Program - Subscriber
Number of customers enrolled
Total number of customers (service agreements) currently enrolled in the program Number Quarterly X X X X X suggested by ED
Will need to determine how best to send subscriber information to vendor (i.e. do we send individual subscriber level data or aggregate the data and provide whole figures).

Program - Subsciber MWs Enrolled Number of MWs enrolled in program Number Quarterly X X X X X suggested by PAs This is a forecasted number. PAs should align on calculation.

Program - Subscriber
Number of low-income customers enrolled Total number of customers enrolled in low-income customer programs (e.g., CARE/FERA) Number Quarterly X X X suggested by PAs
Program - Subscriber
Average customer monthly discount
Average monthly bill discount provided to customers based on actuals Number Annually X X - - X suggested by ED Further discussion between PAs and vendor will be needed to determine how best to display this metric (i.e. in dollars or as a percentage of average bill, or both etc.) Additionally, certain requirements should likely be met for including the customer in the average bill discount calculation (ex: minimum length of enrollment, etc.).

Program - Subscriber
CSGT master-metered accounts The total number of master-metered accounts participating in the CSGT Program Number Quarterly - X - - - D.24-05-065 OP6
This information addresses "subscriber information" as required in OP

6. Program - Subscriber
CSGT master-metered capacity The total capacity, in MWs, allocated to master-metered accounts participating in the CSGT Program Number Quarterly - X - - - D.24-05-065 OP6 This information captures "subscriber information" as required in OP 6.

Project - General
Project name
The name of the project as presented in the contract or other official documents Text Quarterly X X X X X suggested by PAs Project - General
Project facility status
Overall project facility status:

In Development: A PPA has been signed and the project is being developed.

Projects should have an Overall Project Status of "In Development" if they have a Facility Status of "Online-Partially Delivering", or have a Facility Status of "Online-Fully Delivering" but have not yet started the delivery term.

Online: All phases of the Project are online and delivering energy, and the delivery term has commenced.

Terminated: Project was terminated at any point after execution and prior to completing the delivery term under the PPA.

Expired: Project expired after being online and completing the delivery term under the PPA. Text Quarterly X X X X X D.24-05-065 OP6 Project - Capacity Project capacity Project capacity in MW Number Quarterly X X X X X D.24-05-065 OP6 Project - Capacity Annual project generation Total generation of project in MWh Number Annually X X X X X suggested by PAs Project - Techonology
Project technology
Project technology (ex: solar, storage) Text Quarterly X X X X X suggested by PAs Analysis of how this data should be sent to the vendor will be needed since one project can potentially have more than 1 technology (ex: solar + storage).

Project - Location
City
City of project location Text Quarterly X X X X X D.24-05-065 OP6 This project level data can be displayed or summarized as desired in coordination with the vendor.

Project - Location
State
State of project location Text Quarterly X X X X X D.24-05-065 OP6 This project level data can be displayed or summarized as desired in coordination with the vendor.

Project - Location
Zip Code
Zip code of project location Text Quarterly X X X X X D.24-05-065 OP6 This project level data can be displayed or summarized as desired in coordination with the vendor.

Project - Subscriber
Project Sponsors subscribed
Verification if each CSGT Project's Sponsor is receiving energy from that project Text Quarterly - X - - - D.24-05-065 OP6 Project Sponsors can elect to receive energy from the CSGT project they are sponsoring. Verification that the CSGT Project Sponsor is receiving energy from the CSGT Project will be reported as "Yes" or "No".

This information addresses "subscriber information" as required in OP

6. Project - Subscriber
Project Sponsor subscription size
Size of each Project Sponsor's subscription, per CSGT project, in MW Number Quarterly - X - - - D.24-05-065 OP6 Project Sponsors can elect to receive energy from the CSGT project they are sponsoring.

This information addresses "subscriber information" as required in OP

6. Project - Subscriber
Number of low-income qualified customers enrolled Total number of customers enrolled in low-income qualified customer programs (e.g., CARE/FERA) per CSGT project Number Quarterly - X - - - D.24-05-065 OP6 This information addresses "coordination with low-income... programs" as required in OP 6.

Project - Community
Job training The number of workers registered in a State of California approved apprenticeship program, per CSGT project. Number Quarterly - X - - - D.24-05-065 OP6 This information addresses "job training" as required in OP 6.

Project - Community
Local hiring The number of workers whose place of residence is located within a 25- mile radius of the CSGT project. Number Quarterly - X - - - D.24-05-065 OP6 This information addresses "local hiring" as required in OP 6.

All data sent to the vendor will be either at the project level, or overall program level. It is still TBD whether granular level customer data should be sent to the vendor and what value that would provide. Upon more in depth discussion with the PAs, the vendor, and E.D the PAs submit that the information below may change in order to best serve the reporting needs of the program.
# Internal
Source Notes
suggested by PAs
Program cap can be provided one time and updated as needed with the vendor.
suggested by ED
D.24-05-065 OP6
suggested by PAs
D.24-05-065 OP6 May want to have the option to display this by technology type suggested by PAs May want to have the option to display this by technology type suggested by PAs
D.24-05-065 pp.129-130
This metric is derived from total generation less participant usage, so there is no need to send this data to the vendor; therefore it is not listed in the "Fields" table below.

D.24-05-065 pp.129-130
D.24-05-065 pp.129-130
D.24-05-065 pp.129-130
suggested by ED
The number of customers enrolled may need to be segmented by a customer type (example, low income, or res/non res) depending on the program. This will be discussed in more detail with the vendor and needed data elements provided.
suggested by PAs This is a forecasted number. PAs should align on calculation. suggested by PAs
suggested by PAs
suggested by ED
Further discussion between PAs and vendor will be needed to determine how best to display this metric (i.e. in dollars or as a percentage of average bill, or both etc.) Additionally, certain requirements should likely be met for including the customer in the average bill discount calculation (ex: minimum length of enrollment, etc.).

D.24-05-065 OP6 This information addresses "subscriber information" as required in OP 6.

Source Notes
suggested by ED
D.24-05-065 pp.129-130
D.24-05-065 pp.129-130
D.24-05-065 pp.129-130
suggested by ED
Will need to determine how best to send subscriber information to vendor (i.e. do we send individual subscriber level data or aggregate the data and provide whole figures).
suggested by PAs This is a forecasted number. PAs should align on calculation. suggested by PAs
suggested by ED
Further discussion between PAs and vendor will be needed to determine how best to display this metric (i.e. in dollars or as a percentage of average bill, or both etc.) Additionally, certain requirements should likely be met for including the customer in the average bill discount calculation (ex: minimum length of enrollment, etc.).

D.24-05-065 OP6 This information addresses "subscriber information" as required in OP 6.

D.24-05-065 OP6 This information captures "subscriber information" as required in OP 6. suggested by PAs
D.24-05-065 OP6
D.24-05-065 OP6
suggested by PAs
suggested by PAs
Analysis of how this data should be sent to the vendor will be needed since one project can potentially have more than 1 technology (ex: solar + storage).

D.24-05-065 OP6
This project level data can be displayed or summarized as desired in coordination with the vendor.

D.24-05-065 OP6
Project Sponsors can elect to receive energy from the CSGT project they are sponsoring. Verification that the CSGT Project Sponsor is receiving energy from the CSGT Project will be reported as "Yes" or "No".

This information addresses "subscriber information" as required in OP 6.

D.24-05-065 OP6
Project Sponsors can elect to receive energy from the CSGT project they are sponsoring.

This information addresses "subscriber information" as required in OP 6.

D.24-05-065 OP6
This information addresses "coordination with low-income... programs" as required in OP 6.

D.24-05-065 OP6 This information addresses "job training" as required in OP 6.

D.24-05-065 OP6 This information addresses "local hiring" as required in OP 6. # Internal
P.O. Box 800 8631 Rush Street Rosemead, California 91770 (626) 302-6411 Connor Flanigan
Managing Director, State Regulatory Operations
August 29, 2024
ADVICE 5361-E
(Southern California Edison Company - U 338-E)
ADVICE 7361-E
(Pacific Gas and Electric Company - U 39-E)
ADVICE 4497-E
(San Diego Gas and Electric Company - U 902-E)
ADVICE 51-E
(Ava Community Energy)
ADVICE 31-E
(Clean Power Alliance of Southern California)
ADVICE 32-E
(CleanPowerSF)
ADVICE 31-E
(Lancaster Choice Energy)
ADVICE 81-E
(Marin Clean Energy)
ADVICE 37-E
(Peninsula Clean Energy)
ADVICE 26-E
(Pico Rivera Innovative Municipal Energy)
ADVICE 23-E
(San Diego Community Power)
ADVICE 24-E
(San Jacinto Power)
ADVICE 38-E
(San Jose Clean Energy)

PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

ENERGY DIVISION
An EDISON INTERNATIONAL >< Company
ADVICE 5361-E et al.
(U 338-E) - 2 - August 29, 2024
SUBJECT: Joint Submittal Outlining Workshop Results and Process Improvements Pursuant to Ordering Paragraph 8 of Decision 24-05-065.

PURPOSE
In accordance with Ordering Paragraph (OP) 8 of Decision (D.) 24-05-065 (the Decision), Southern California Edison Company (SCE) submits this advice letter on behalf of itself, Pacific Gas and Electric Company (PG&E), and San Diego Gas & Electric Company (SDG&E) (together, the Investor-Owned Utilities (IOUs)) and Clean Power Alliance of Southern California (CPA), CleanPowerSF, CalChoice,1 Ava Community Energy (Ava), Marin Clean Energy (MCE), Peninsula Clean Energy Authority (PCE), San Jose Clean Energy (SJCE) and San Diego Community Power (SDCP) (together, the participating CCAs) to provide workshop results and propose the format and specific data to be included in the California Distributed Generation Statistics (DGStats) reporting website.

BACKGROUND
On May 31, 2022, the IOUs each filed an application for review of their Disadvantaged Community – Green Tariff (DAC-GT), Community Solar Green Tariff (CSGT), and Green Tariff Shared Renewables (GTSR) programs pursuant to D.18-06-027 and D.21- 12-036. These applications were consolidated into one proceeding. The Administrative Law Judge (ALJ) issued a Scoping Memo and Ruling on December 2, 2022, which established the scope and schedule for the proceeding including providing the opportunity for stakeholders to propose modifications to existing tariffs or establishing a new tariff or program, if doing so would be beneficial to ratepayers.

On May 30, 2024, the California Public Utilities Commission (CPUC or Commission) adopted the Decision modifying and streamlining existing Green Access Programs (GAP) and adopting a Community Renewable Energy (CRE) Program, pursuant to Assembly Bill (AB) 2316 (Ward, Stats. 2022) and Pub. Util.

Code Section 769.3.

On July 19, 2024, the IOUs and participating Community Choice Aggregators (CCA) facilitated a workshop with Energy Division (ED) and relevant stakeholders to determine the format and specific data to be included in the California Distributed Generation Statistics (DGStats) website reporting pursuant to Decision OP 7.

1 CalChoice acts as program administrator for Lancaster Choice Energy (LCE), Pico Rivera Innovative Municipal Energy (PRIME), and San Jacinto Power (SJP).

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Pursuant to Decision OP 8, within 45 days after facilitating the workshop, noted above, the IOUs and participating CCAs submit this joint Tier 1 Advice Letter outlining the agreed upon data reporting and any efforts planned to better coordinate amongst the various Program Administrators (PAs) and to automate the data collection and transfer process.

DISCUSSION
Overview of DGStats
The Commission ordered the creation of the California Solar Statistics website in 2006 to serve as the official public reporting site for the California Solar Initiative (CSI).2 In 2015, recognizing the benefits of hosting distributed generation data beyond CSI and Net Energy Metering solar statistics, ED worked with the IOUs to create the new DGStats website and to transfer data from California Solar Statistics to DGStats.

Further Commission decisions and ED guidance directed the IOUs to begin publishing to DGStats project-level data from the Self-Generation Incentive Program (SGIP), Solar on Multifamily Affordable Housing (SOMAH) Program, and New Solar Homes Partnership (NSHP).3 In October 2019, the Commission adopted Resolution E-5030 authorizing ED to oversee contracts for work required to maintain and expand the DGStats website. ED is authorized to define future scopes of work, manage contract deliverables, and set funding levels for the site.4
Workshop Summary and Green Access Programs Reporting Overview As referenced above, the PAs facilitated a workshop on July 19, 2024 (the July Workshop) to determine the format and specific public, non-confidential data to be included in the DGStats website reporting, including specific metrics identified in OP 6 of the Decision.5 At the workshop, SCE, the singular PA for the discontinued ECR program and CPA the singular PA for the discontinued CSGT program proposed that although not required by the Decision, metrics for both of these closed programs should be reported on the DGStats website for completeness. There were no objections from ED or other stakeholders.

The following discussion proposes metrics to be included in future DGStats reporting for all of the Green Access Programs (GAP), which include the modified DAC-GT and

2 D.06-01-024, Interim Order Adopting Policies and Funding for the California Solar Initiative, R.04-03-017 (Jan. 17, 2006).
3 D.17-12-022, Decision Adopting Implementation Framework for Assembly Bill 693 and Creating the Solar on Multifamily Affordable Housing Program, R.14-07-002 (Dec. 18, 2017)
4 R. E-5030, Authorizing Energy Division to Oversee Contracts for Work Required to Maintain and Expand the California Distributed Generation Statistics Website (October 24, 2019) 5 Id. at 173 (OP 7).

ADVICE 5361-E et al.
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CSGT programs, the modified GT and ECR programs, and the CRE Program. The cadence in which metrics should be reported after the DGStats website is updated and live, in addition to plans for interim period reporting prior to the transition to the updated DGStats website are also addressed.

As discussed in the July Workshop, specific metrics under consideration include those directed by OP 6 of the Decision, metrics currently reported to the Commission in existing program-related reports, and additional metrics suggested by ED or the PAs.

Given the similarities between programs, the PAs present metrics, reporting cadences, interim reporting, and other concepts which are applicable to all programs in the “Green Access Programs Reporting” section below and provide more detail about each program, its current metrics, and any specific program reporting needs in the “Program Reporting Specifics” section.

Through workshop discussions and further conversation after the workshop, the PAs reached alignment on GAP reporting on the DGStats website. However, all PAs and ED acknowledged that more in depth discussions will need to occur to build out a successful reporting platform for each program on DGStats. These discussions with the DG Stats website vendor, ED and participating PAs are likely to lead to further refinement and/or potential additions, reductions, or changes to reporting metrics.

Therefore, the information presented below should be treated only as an initial foundation for future discussions with the vendor and ED, and not as a final design document nor as a scope of work.

Green Access Programs Reporting
In Appendix A-2, the PAs have included a matrix that shows PA by GAP to understand which PA will be reporting on which GAP on the DGStats website.

The PAs propose that GAP data provided to the DGStats vendor by each load serving entity (LSE) be LSE-specific. This will allow the data to be presented on the DGStats website either by LSE, aggregated for the purposes of reporting statewide figures, or through another level of aggregation as determined by the vendor, ED, and reporting PAs in future implementation discussions.

Metrics vs. Fields
Two tables are presented in Appendix A-1: one that lists GAP metrics and one that lists GAP fields. The “Metrics” table presents metrics that are agreed upon as prime candidates for reporting on the DGStats website by program. The PAs define a metric as a measure of quantitative assessment used to track performance of a program.

The PAs further agree that all metrics displayed on the DG Stats website should be presented at the “program” level, as opposed to the “project” level. To illustrate the difference between a program and a project, we can consider that one program such as ADVICE 5361-E et al.
(U 338-E) - 5 - August 29, 2024
DAC-GT will consist of multiple projects. A project is a single contract for the installation of renewable resources by a developer to support a program. Given this hierarchical and one to many relationship between a program and projects, the PAs agree that displaying metrics at the program level provides the correct amount of granularity, while still allowing the end user to aggregate that programmatic data in various ways (i.e., by LSE, service territory, zip code, etc.). To further illustrate the relationship between a program and a project, we can look at how the PAs intend to measure program capacity. Program capacity is a metric that would consist of the sum of each projects’ capacity dedicated to a given program, such as DAC-GT. However, only the program level total would be displayed, not the individual project MWs that make up the total.

Naturally, metrics from one program should not be compared to metrics from another program.

The PAs core programmatic metrics fall into five broad categories as shown below:

1. Cost

2. Capacity

3. Subscriber

4. Projects

5. RECs
In addition to programmatic reporting, the CSGT program is the one program that intends to display “project” level information on the DG Stats website. Due to the fact that there are only four total projects in the CSGT program, providing “project” level information is digestible and adds value. These differences for the CSGT program will be detailed in the “Program Reporting Specifics” section under “CSGT Reporting.” In contrast to “metrics”, a “field” is defined as a data element that refers to an attribute or property about the entity (i.e., program, project, customer etc.) in question. In some cases, fields may need to be provided to the vendor to help display a metric in a meaningful way. In other cases, the metric itself is the value in a field.

In the “Fields” table shown in Appendix A-1, the PAs present fields as a building block that can be leveraged in initial discussions with the vendor and to ensure all required information is captured appropriately (i.e., project level information). For simplicity, fields are given the same five categories referenced above, with the addition of community, technology, and location. However, sometimes these categories relate to a project instead of a program, as opposed to “Metrics” which all relate to a program. The PAs understand that future discussions with the vendor will be necessary to ensure the data (fields) are transferred to the vendor in the correct format and at the correct level of granularity for successful reporting and that ensures data confidentiality.

The PAs propose that the following metrics be included for the DAC-GT, CSGT, modified GT, ECR, and CRE programs on the DGStats website in accordance with the ADVICE 5361-E et al.
(U 338-E) - 6 - August 29, 2024
Decision. Additional information, including the specific definition for each category discussed below is included in Appendix A-1.

Programmatic Information – Cost
During the July Workshop, Energy Division staff recommended that the DGStats reporting include annual program costs. The PAs support including this metric on the DGStats website for all programs.

The proposed programmatic cost-related metric for the GAP programs is summarized as the following:

1. Annual program costs
Programmatic Information – Capacity
All parties agreed that program capacity is an important measure for public visibility.

Additionally, PAs agreed that in some cases, such as when comparing the program cap in MW to the number of MWs online for a program in a given quarter, “MWs online” is the preferred metric. However, in other cases, such as at the end of the year, once the PAs have access to the total amount of energy a program has generated for the year as well as the corresponding amount of energy program participants have consumed in that year, it can be more valuable to look at capacity in terms of energy (i.e. MWhs).

Therefore, the PAs propose collecting and presenting both MWs and MWhs associated with each program on the DG Stats website.

The proposed programmatic capacity-related metrics for the GAP programs are summarized as the following:

1. Program Cap

2. MWs procured

3. MWs online

4. Annual program generation (MWh)

5. Annual Unsubscribed MWh
Programmatic Information – Subscriber
The PAs propose that the “subscriber information” requested in OP 6 of the Decision6 is represented by the number of enrolled customers and average monthly discounts provided to those customers as applicable.

6 Id. at 173 (OP 6).

ADVICE 5361-E et al.
(U 338-E) - 7 - August 29, 2024
Additionally, during the July Workshop, ED suggested subscriber information include the “number of customers enrolled”. PAs determined that the number of customers enrolled should always be reported at the lowest level of granularity available to define a customer (i.e., the electric service agreement level). All PAs agreed they are reporting at the service agreement level in their current reporting and should continue to do so.

Parties at the workshop further acknowledged that different programs may have different needs to segment the number of customers enrolled by different customer characteristics. Different ways to segment the number of customers enrolled could include, but are not limited to, customer class, low-income status, business type, or Title 24 compliance driven enrollments. Parties agreed that further discussions will be needed by all participating PAs within a program to identify the most meaningful ways to segment customers for any given program.

In addition, to provide an overall snapshot of the degree to which the program has been enrolled or subscribed to by customers, the PAs suggest including the number of enrolled customers presented in MW. The creation of this metric typically requires some type of forecast in terms of future customer usage as well as a general capacity factor to apply to the MWs of generation online. PAs agree that the methodology used to arrive at the MWs of customers enrolled as well as any assumed inputs to this calculation should be discussed and agreed upon by the PAs and ED. Any divergences from methodologies among PAs, if at all, should be minimal to ensure comparisons across PAs are valid and appropriate.

OP 6 further contemplates reporting on the coordination with low-income and clean energy programs. With regard to low-income programs, as noted above, where appropriate, (potentially in a program such as the CRE Program), PAs intend to report on the number of customers enrolled in low-income programs, which for most programs would be the total number of enrolled customers by California Alternate Rates for Energy (CARE) and/or Family Electric Rate Assistance (FERA) program status. “Coordination with low-income programs” for programs, like DAC-GT or CSGT, means reporting on the number of new CARE/FERA enrollments in the process of enrolling customers in the program on a quarterly basis7. Though this metric remains relevant for CSGT, it is no longer as relevant for DAC-GT, as PAs move to implement auto-enrollment processes8.

Additionally, it would be difficult for PAs to concisely and uniformly report on coordination with clean energy programs as each PA offers different programs, and “clean energy programs” are not clearly defined in the decision. The PAs, therefore, recommend removing these reporting requirements for inclusion on the DGStats

7 Resolution E-4999 at 63 (OP 1(f)).
8 D.24-05-065 at 133 (“To be clear, Utilities and participating CCAs shall follow the auto-enrollment practice adopted by the Commission in D.20-07-008 and reiterated in Resolution E-5124.”)
ADVICE 5361-E et al.
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website at this time, and instead propose reporting the total number of low-income customers enrolled, where appropriate.

The proposed programmatic subscriber-related metrics for the GAP programs are summarized as the following:

1. Number of customers enrolled

2. Number of low-income customers enrolled

3. MWs Enrolled

4. Average customer monthly discount
Programmatic Information – Projects

The participating CCAs, the joint IOUs, and ED all agree that project level information is important to provide so that certain programmatic metrics can be displayed on the DGStats website. The project-specific related metrics that were discussed at the July Workshop per OP 6 of the Decision are “projects approved” and “projects completed.” Again, these would be reported in a summarized manner at the program-level.

It was also proposed that project facility status and location of project would be important fields to collect for help with displaying metrics by various segments.

Additionally, the PAs propose providing the following fields to the vendor: 1) project name; and 2) technology type for each project.

The proposed project-related metrics for the GAP programs are summarized as the following:

1. Number of projects procured (“Projects approved” per D.24-05-065)

2. Number of projects online (“Projects completed” per D.24-05-065) The proposed programmatic project-related fields for the GAP programs are summarized as the following:

1. Project name

2. Project facility status

3. Project capacity

4. Annual project generation

5. Project technology type

6. Project location (city, state, zip code)
ADVICE 5361-E et al.
(U 338-E) - 9 - August 29, 2024
Programmatic Information – RECs
The Decision eliminated the Green-e Certification process.9 In lieu of Green-e Certification, the Decision requires that PAs conduct their own validation and tracking by including the following details in their modified program reporting after the retirement of Renewable Energy Certificates (RECs): megawatt-hours (MWh) of participant usage, MWh of Renewables Portfolio Standard (RPS) RECs retired for participants, and remaining MWh of usage to account for with program RECs.10 The PAs understand this to mean that RECs retired for participants should be segmented into MWh of RPS RECs retired for participants from interim resources, and MWhs of RECs retired for program participants that are from dedicated programmatic resources. The “MWh of participant usage” should match the total number of MWh of total RECs retired for participants.

These data points are applicable to all programs, except the CRE Program, whose program design is still under consideration by the Commission.

The proposed programmatic REC-related metrics for the GAP programs are summarized as the following:

1. Annual MWh of participant usage

2. Annual MWh of RPS/interim RECs retired for participants

3. Annual MWh of programmatic/dedicated RECs retired for participants Reporting Cadence

The PAs support reporting program metrics on a quarterly basis as required under OP 6 of the Decision. However, while most metrics can be reported on a quarterly basis, some of the above metrics, including those metrics that were not previously included in program reporting, need to be updated on an annual basis, such as annual program costs. Reporting certain metrics on an annual basis will ensure that PAs can provide the actual data rather than a forecast or estimate. Additionally, PAs retire RECs on an annual basis after participant usage and developer generation has been finalized for the prior calendar year, and therefore PAs propose that metrics related to MWhs of generation and usage (i.e., total MWhs of project generation, MWhs of participant usage, MWhs of dedicated and/or interim RECs retired for participants, and

9 Id. at 172 (OP 3(g)) (“Green-e certification is no longer required. Consistent with Ordering Paragraph 6 below, Quarterly reporting to California Distributed Generation Statistics (DGStats) website, or another website as determined by ED, shall include: megawatt-hours (MWh) of participant usage; MWh of Renewable Portfolio Standard (RPS) Renewable Energy Credits (RECs) retired for participants; and remaining MWh of usage to account for which program RECs.”)
10 Id.

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unsubscribed MWhs) be made on an annual cadence as well, after RECs have been retired.

Lastly, the PAs propose that average monthly customer discount be calculated and reported on an annual basis once actuals from the year have been finalized, and that the average monthly discount be derived from discounts provided every month of the calendar year.

The proposed cadence for updating each reported metric is provided in more detail in Appendix A-1.

Interim Reporting

In the interim period prior to the implementation of reporting on the DGStats website, PAs will continue to file quarterly reports for the GAP programs.11 This will ensure that program reporting continues without interruption and/or unnecessary confusion. There were two criteria that were established at the July 19 workshop that must be true to begin reporting on the DGStats website:

1. The GAP program in question must be fully designed and have data to provide and;

2. The DGStats website module for the GAP program in question must be live and fully operational.

Once these two requirements are met, the PAs will switch to reporting in the new system to ensure centralized reporting. The IOUs and Participating CCAs do not believe that it would be beneficial to transfer any historical reporting information into the DGStats website. This would be an unnecessary expense.

Efforts to Better Coordinate and Automate the Data Collection and Transfer Process OP 8 directs the IOUs and participating CCAs to outline “any efforts planned to better coordinate amongst the various Program Administrators and to automate the data collection and transfer process.” First, addressing plans to better coordinate, the PAs agree that once a vendor is selected to update the DGStats website, a source of funding is determined, and the GAP programs are fully designed, the PAs for each program will meet to begin discussions with the vendor to initiate website development.

The PAs anticipate there may be standing meetings to discuss scope of work, timing for both the buildout of the GAP website modules, and timing related to when the quarterly and annual data will be provided to the vendor and when the updates will be made to the website, etc. Once the website is established, the PAs may also benefit from hosting

11 Per D.21-12-036, PG&E is required to file monthly progress reports for its GTSR program.

As directed, PG&E will continue the monthly cadence unless a letter from the Executive Director of the Energy Division is received that adjusts the required cadence to quarterly.

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optional meetings on a quarterly or semi-annual cadence (at least initially) to ensure that the website is functioning as expected, and to address any issues or discuss any areas for improvements.

Next, given the DGStats vendor for 2025 and beyond is still to be determined, the PAs agreed that it is too early to discuss any level of automation as it relates to the data collection and transfer process. Internal automation has a cost associated with it, and each PA’s internal Information Technology systems will operate differently across the various programs. In some instances, and depending on the PA and program, the data collection process may be simple to automate. In other cases, manual reporting may be preferred to provide the data in the needed format for data transfer to the vendor.

Data transfer is different than data collection, and this difference is important when considering automation. Data collection refers to how each LSE collates the data internally, whereas data transfer relates to the process by which the LSE sends the data to the vendor for display on the website. If automation is desired, the automation of data transfer and associated cost and the funding source for this potential expense will need to be discussed upon selection of a vendor for the DGStats website. Building an Application Programming Interface (API) is one way to automate data transfer, though given the associated costs, it may be more beneficial to simply transfer files to the vendor “manually” using Secure File Transfer Protocol (SFTP) each quarter. Any level of automation is likely to substantially increase the funding required to report the metrics. Given the potentially large cost associated with any automation between multiple PAs and a chosen vendor, the PAs request that if this is needed, it be mandated by Commission direction and with an appropriate cost recovery mechanism.

Similarly, PAs request that a budget and funding source for the DGStats work be provided by the Commission. This could be in the form of a Resolution in the DGStats proceeding that would increase the funding for the DGStats website to account for GAP reporting needs and also order the incorporation of community solar statistics into the contract.12 The PAs put forth this proposal as the most cost-effective and streamlined approach. The participating CCAs will need to determine if one PA should hold the master contract with the vendor for all participating CCAs.

PROGRAM REPORTING SPECIFICS

DAC-GT & CSGT PROGRAMS
Current Reporting Requirements

12 IOUs will establish a co-funding agreement ensuring ratepayer indifference between service territories.

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The IOUs and the CCAs, as PAs, are subject to the same DAC-GT and CSGT reporting requirements. The PAs have been filing quarterly and semi-annual reports for the DAC-GT and CSGT programs pursuant to Resolution E-4999.

The current reporting requirements are as follows:

DAC-GT/CSGT Quarterly Reports:
• Capacity procured
• Capacity online
• Customers subscribed
• DAC census tract where project is located
• Number of participating customers in each DAC census tract • Number of customers newly enrolled in CARE/FERA
CSGT Semi-Annual Reports:
• Number of income-qualified customers subscribed to each CSGT project • Capacity allocated to subscribed customers
• Whether waitlist of non-qualified customers exists; size of waitlist • Whether Project Sponsor is receiving bill credits from the Project • Project sponsor’s subscription size
• Number of master-metered accounts participating in CSGT • Total program capacity allocated to master-metered accounts

Proposed Updated Reporting for DAC-GT/CSGT
In light of the Decision, the PAs recommend keeping the existing metrics above when transitioning to DGStats reporting with several exceptions below for the DAC-GT/CSGT programs.

Metrics to Discontinue

The PAs propose to discontinue reporting which DAC census tract the project is located in as the project siting requirements were expanded under the Decision.13

PAs currently report on the number of customers in each DAC census tract as part of the DAC-GT/CSGT quarterly reports. The PAs propose that this metric be discontinued

13 See D.24-05-065 at 170 (OP 3(a)) (“Site requirements are revised to allow eligible projects to be located no more than five miles from eligible disadvantaged communities census tracts.”)
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in order to streamline reporting as all customers, with the exception of CSGT sponsors, must be residents in a DAC.

The PAs propose to discontinue reporting on capacity allocated to subscribed customers and information on wait-lists of non-qualified customers (verification if a list exists and, if so, the size of each list) as part of the CSGT semi-annual reports. The metric regarding capacity allocated to subscribed customers should be discontinued as it provides redundant information to the program capacity metrics that will be reported in DGStats. The wait-list information should also be discontinued to streamline reporting of useful and timely information.

Proposed Updated CSGT Reporting

While the Decision discontinued future solicitations for the CSGT program, reporting for existing CSGT projects would continue. PAs that have already contracted for CSGT projects or have CSGT procurement in existing active solicitations at the time of issuance for the Decision and plan to continue their CSGT program will report on program metrics and fields in accordance with OP 6 of the Decision.14 The PAs propose that the CSGT program reporting in DGStats include all the same metrics and fields as DAC-GT. However, since the CSGT Program has additional requirements and provisions (e.g., Project Sponsors) beyond the modified DAC-GT program, CSGT PAs should report on additional CSGT project and program specific data beyond that reported for DAC-GT. The PAs propose CSGT PAs report on two additional metrics and six additional fields: two regarding programmatic information (reflected in both metrics and fields) and four fields regarding project information.

The PAs also proposes one modification to CSGT reporting not discussed below. The Program—Subscriber metric category should not include Project Sponsor data in the “average customer monthly discount” metric.15 Other reporting proposals regarding Project Sponsors are addressed below.

14 PAs who will no longer offer the CSGT program, will no longer report on CSGT following the full transition of their CSGT program to the modified DAC-GT. 15 With respect to calculating an average customer monthly discount for CSGT Reporting, CSGT PAs should not include a Project Sponsor’s bill discount (if the Project Sponsor elects to receive one) as a Project Sponsor is eligible to receive up to 25 percent of a CSGT project’s output (according to Resolution E-4999, Findings and Conclusions 24). A Project Sponsor’s subscription size (and bill discount - if the Project Sponsor elects to receive one) could be significantly larger than residential CSGT subscribers and could skew average bill discount data.

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Additional Programmatic Information
PAs operating a CSGT program will report on two additional program metrics that will also be reflected as two additional program fields: the number of master-metered accounts participating in the CSGT program and the total CSGT capacity allocated to those master-metered accounts under the Program-Subscriber field category. The PAs propose reporting on two CSGT-specific program metrics relative to master-metered accounts to better capture all potential CSGT subscribers in DGStats: the number of master-metered accounts participating in the CSGT program, and the total program capacity allocated to those master-metered accounts.

Additional Project Information
PAs operating a CSGT program will report on four additional project fields, two under the Project-Community field category and two under the Project-Subscriber field category. CSGT PAs will report on job training, and local hiring under the Project Community category. Those fields will include the number of workers registered in a State of California approved apprenticeship program and the number of workers whose place of residence is located within a 25- mile radius of the CSGT project, respectively.

This information is project-specific and improves visibility into project information if displayed at the project-level.

Under the Project-Subscriber field category, CSGT PAs will report if a Project Sponsor is receiving energy and, if so, the Project Sponsor’s subscription size. This information is also project-specific and provides greater visibility into project information if displayed at the project-level.

PAs operating a CSGT program will continue to provide information on the number of income-qualified customers subscribed to each CSGT project.

Modified Green Tariff & ECR Programs
The Decision modified the Green Tariff option and closed the ECR option to all new procurement not currently under negotiation or contract. SCE is the only utility with dedicated ECR projects that is either online, approved or under negotiation.

Current Reporting Requirements
ADVICE 5361-E et al.
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Decision 15-01-051 directed the participating IOUs to submit monthly GTSR program progress reports as well as an annual program progress report. In Resolution E-5028,16 the Commission streamlined and consolidated GTSR reporting requirements.

Specifically, the Commission modified the frequency of its GTSR program reports from monthly to quarterly.17
The current reporting requirements are as follows:

Quarterly GTSR Program Progress Reports18:
• “Available capacity” data at the most detailed level feasible, updated monthly, and work to increase the precision of the information over time. • Summary of monthly advisory group activities, or consultation with Community Based Organizations (CBOs), if any.
• ECR Contract Report
• Attach Generation Transfer Report (Reported in Quarter 3) Annual GTSR Program Progress Reports:
• Enrollment Reporting, including “available capacity” data at the most detailed level feasible.
• One page summary tracking the amount and cost of generation transferred between the RPS and GTSR Program.
• GTSR Revenue and Cost Reporting summary.
• Summary of advisory group or advising network activities, including information regarding frequency of meetings, topics discussed, and any other relevant information.
• CCA Code of Conduct report. If applicable, summarize any marketing or lobbying efforts that are, or could reasonably be interpreted to be, subject to the CCA Code of Conduct.
• Supplier diversity.

16 Ordering Paragraph 6. The specific reporting requirement changes are described in detail in Attachment C of PG&E Advice Letter 3920-G/5206-E.
17 Per D. 21-12-036, this reduced schedule was rescinded for PG&E only, with additional reporting requirements added; the Executive Director, or designee can inform PG&E when it may revert back to quarterly reporting.
18 Per D. 21-12-036, this reduced schedule was rescinded for PG&E only, with additional reporting requirements added; the Executive Director, or designee can inform PG&E when it may revert back to quarterly reporting.

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(U 338-E) - 16 - August 29, 2024
• Summary of CARE enrollment figures including location; location of CARE customers in relation to areas eligible for Environmental Justice (“EJ”) Projects and in relation to planned or existing EJ Projects.
• Reports of fraud or misleading ads
• Enrollment figures for low-income customers and subscribers who speak a language other than English at home
• GTSR 20-year forecast19
Inclusion of ECR in DGStats Reporting
As discussed at the July 19 Workshop, despite the closure of the GTSR-ECR to new procurement, SCE will continue reporting program metrics under OP 6 referenced in Appendix A-1 under the ECR program column for projects that are currently online and those that will come online in the future, in line with its current process until DGStats is implemented. This approach ensures a uniform and dependable method across all programs.

Metrics to Discontinue

The PAs propose that both supplier diversity and summary of CARE enrollment figures be discontinued from the annual report. The PAs’ current and potential contracts with GT and ECR partners have not counted toward supplier diversity goals, and therefore this metric is not applicable to the programs. Additionally, the CARE customer enrollment metric was created before the existence of DAC-GT/CSGT. Given the modified GT program is focused on providing a 100% renewable energy product for the general market population, the PAs recommend removing the low-income enrollment metric and the number of subscribers who speak a language other than English at home. The measure of program enrollment in these populations is not relevant and is not a measure of success for the modified GT or ECR programs.

The monthly advisory group activities are not included as a “metric” or evaluated for purposes of this advice letter as they are being evaluated as part of A. 22-05-022. They are listed here only for completeness and will not be included as a metric in DGStats.

Additionally, job training and workforce development tracking, although mentioned in the Decision, were never a goal nor a requirement for the GT and ECR Programs. Inclusion of these metrics is therefore unnecessary.

19 The GTSR 20-year forecast is not included as a “metric” or evaluated for purposes of this Advice Letter. It is listed here only for completeness.

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(U 338-E) - 17 - August 29, 2024
Last, as the average customer monthly discount is not applicable to the modified GT or ECR programs, the PAs do not intend to display that information on the website.

Community Renewable Energy (CRE) Program
The Decision adopted the foundational elements of a new Community Renewable Energy Program. In June 2024, the Administrative Law Judge issued a ruling seeking additional party comments on programmatic details regarding the implementation of the CRE Program. Parties responded to questions in July of 2024. During the July 19 workshop, participating parties acknowledged that the parameters of the CRE Program are still under development in the proceeding, (A. 22-05-022, and related matters), and should not be discussed outside of vague generalities until program details are finalized.

Nonetheless, the group agreed that the number of MWs procured and participation levels in the CRE Program (by relevant segments) would be important metrics to establish once the program is created. Once a decision that further defines the CRE Program is adopted, the parties will be able to reconvene and discuss appropriate metrics for the program in more detail. Open dialogue between the IOUs, the participating CCAs, and ED will be important to ensure the chosen metrics measure important program objectives. The IOUs and CCAs acknowledged that an additional advice letter can be submitted at a later date to propose CRE Program metrics for incorporation onto the DGStats website.

TIER DESIGNATION
In accordance with OP 8 of this Decision, this advice letter is submitted with a Tier 1 designation.

EFFECTIVE DATE
This advice letter will become effective August 29, 2024, the same date submitted.

NOTICE
Anyone wishing to protest this advice letter may do so only electronically. Protests must be received no later than 20 days after the date of this advice letter. Protests should be submitted to the CPUC Energy Division at:

E-mail: [email protected]
In addition, protests and all other correspondence regarding this advice letter should also be sent electronically to the attention of:

For SCE:

Connor Flanigan
ADVICE 5361-E et al.
(U 338-E) - 18 - August 29, 2024
Managing Director, State Regulatory Operations
Southern California Edison Company
E-mail: [email protected]

and

Adam Smith
Director, Regulatory Relations
c/o Karyn Gansecki
Southern California Edison Company
E-mail: [email protected]
For PG&E:

Sidney Bob Dietz II
Director, Regulatory Relations
c/o Megan Lawson
Pacific Gas and Electric Company
E-mail: [email protected]
For SDG&E:

Attn: Greg Anderson
Regulatory Tariff Manager
E-mail: [email protected] and [email protected]
For Joint CCAs:

Attn: Brittany Iles
Counsel for Joint CCAs
E-mail: [email protected]
There are no restrictions on who may file a protest, but the protest shall set forth specifically the grounds upon which it is based and must be received by the deadline shown above.

In accordance with General Rule 4 of GO 96-B, SCE is serving copies of this advice filing to the interested parties shown on SCE’s GO 96-B and A.22-05-024 et. al. service lists. Address change requests to SCE’s GO 96-B service list should be directed by electronic mail to [email protected] or at (626) 302-6838. For changes to all other service lists, please contact the Commission’s Process Office at (415) 703-2021 or by electronic mail at [email protected].

ADVICE 5361-E et al.
(U 338-E) - 19 - August 29, 2024
To view other SCE advice letters filed with the Commission, log on to SCE’s web site at https://www.sce.com/wps/portal/home/regulatory/advice-letters.

For questions, please contact Joe Cox at (626) 302-4811 or by electronic mail at [email protected]
Southern California Edison Company
/s/ Connor Flanigan
Connor Flanigan
CF:jc:bvs
Enclosure

ADVICE LETTER

SUMMARY

ENERGY UTILITY
Company name/CPUC Utility No.:

Utility type:

Phone #:

EXPLANATION OF UTILITY TYPE

ELC GAS

PLC HEAT
MUST BE COMPLETED BY UTILITY (Attach additional pages as needed) Advice Letter (AL) #:

WATER
E-mail:

E-mail Disposition Notice to:

Contact Person:

ELC = Electric
PLC = Pipeline
GAS = Gas
HEAT = Heat WATER = Water
(Date Submitted / Received Stamp by CPUC)
Subject of AL:

Tier Designation:

Keywords (choose from CPUC listing):

AL Type: Monthly Quarterly Annual One-Time Other:

If AL submitted in compliance with a Commission order, indicate relevant Decision/Resolution #:

Does AL replace a withdrawn or rejected AL? If so, identify the prior AL:

Summarize differences between the AL and the prior withdrawn or rejected AL:

Confidential treatment requested? Yes No
If yes, specification of confidential information:

Confidential information will be made available to appropriate parties who execute a nondisclosure agreement. Name and contact information to request nondisclosure agreement/ access to confidential information:

Resolution required? Yes No
Requested effective date: No. of tariff sheets:

Estimated system annual revenue effect (%):

Estimated system average rate effect (%):

When rates are affected by AL, include attachment in AL showing average rate effects on customer classes (residential, small commercial, large C/I, agricultural, lighting).

Tariff schedules affected:

Service affected and changes proposed1:

Pending advice letters that revise the same tariff sheets:
1 Discuss in AL if more space is needed.

California Public Utilities Commission
California Public Utilities Commission
Energy Division Tariff Unit Email:

[email protected]
Protests and correspondence regarding this AL are to be sent via email and are due no later than 20 days after the date of this submittal, unless otherwise authorized by the Commission, and shall be sent to:

Contact Name:

Title:

Utility/Entity Name:

Telephone (xxx) xxx-xxxx:

Facsimile (xxx) xxx-xxxx:

Email:

Contact Name:

Title:

Utility/Entity Name:

Telephone (xxx) xxx-xxxx:

Facsimile (xxx) xxx-xxxx:

Email:

CPUC
Energy Division Tariff Unit
505 Van Ness Avenue
San Francisco, CA 94102
ENERGY Advice Letter Keywords
Affiliate Direct Access Preliminary Statement
Agreements Disconnect Service Procurement
Agriculture ECAC / Energy Cost Adjustment Qualifying Facility Avoided Cost EOR / Enhanced Oil Recovery Rebates
Balancing Account Energy Charge Refunds
Baseline Energy Efficiency Reliability
Bilingual Establish Service Re-MAT/Bio-MAT
Billings Expand Service Area Revenue Allocation
Bioenergy Forms Rule 21
Brokerage Fees Franchise Fee / User Tax Rules
CARE G.O. 131-D Section 851
CPUC Reimbursement Fee GRC / General Rate Case Self Generation Capacity Hazardous Waste Service Area Map
Cogeneration Increase Rates Service Outage
Compliance Interruptible Service Solar
Conditions of Service Interutility Transportation Standby Service Connection LIEE / Low-Income Energy Efficiency Storage
Conservation LIRA / Low-Income Ratepayer Assistance Street Lights Consolidate Tariffs Late Payment Charge Surcharges
Contracts Line Extensions Tariffs
Core Memorandum Account Taxes
Credit Metered Energy Efficiency Text Changes
Curtailable Service Metering Transformer
Customer Charge Mobile Home Parks Transition Cost
Customer Owned Generation Name Change Transmission Lines Decrease Rates Non-Core Transportation Electrification
Demand Charge Non-firm Service Contracts Transportation Rates Demand Side Fund Nuclear Undergrounding
Demand Side Management Oil Pipelines Voltage Discount
Demand Side Response PBR / Performance Based Ratemaking Wind Power Deposits Portfolio Withdrawal of Service
Depreciation Power Lines

APPENDIX A
Contact [email protected] for the excel sheet

SEPTEMBER FILINGS

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Consider
New Approaches to Disconnections and
Reconnections to Improve Energy Access and
Contain Costs.

R.18-07-005
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY COMMENTS

ON THE PROPOSED DECISION EXTENDING CURRENT PROPORTIONAL

ALLOCATION OF PAYMENT ON PAST-DUE BILLS BETWEEN INVESTOR-OWNED UTILITIES AND COMMUNITY CHOICE AGGREGATORS Evelyn Kahl,
General Counsel and Director of Policy
Leanne Bober,
Senior Counsel

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
1121 L Street, Suite 400
Sacramento, CA 95814
Telephone: (510) 980-9459
E-mail: [email protected]
September 3, 2024
i

TABLE OF CONTENTS
I. INTRODUCTION ...............................................................................................................1 II. SDG&E’S REQUEST FOR SCE’S ZIG ZAG TO BE AUTHORIZED IN PLACE OF PROPORTIONAL ALLOCATION SHOULD BE REJECTED .....................2 A. The Zig Zag Method in Practice Creates a Masked “Waterfall” to the IOUs and Should Not Be Allowed...........................................................................2 B. The Zig Zag Should be Rejected as it Has a Material Negative Impact on CCAs and is Operationally Complex to Implement and Manage.......................3 III. PG&E’S ASSERTION OF COMMISSION ERROR FOR FAILURE TO

CONSIDER THE RECORD ON VARIOUS ISSUES IS BASELESS AND
SHOULD BE REJECTED ...................................................................................................4 IV. PG&E’S AND SDG&E’S REQUESTS FOR THE PROPOSED DECISION

TO SPECIFY A SUNSET DATE FOR THE PROPORTIONAL
ALLOCATION METHOD SHOULD BE REJECTED ......................................................4 V. SDG&E’S REQUEST FOR “FLEXIBILITY” TO MUTUALLY ALTER

THE PAYMENT ALLOCATION METHODOLOGY THROUGH A JOINT
ADVICE LETTER WITH LOCAL CCAS SHOULD BE REJECTED .............................5 VI. CONCLUSION ....................................................................................................................5 ii

SUMMARY OF RECOMMENDATIONS
The California Community Choice Association recommends that the California Public Utilities Commission (Commission):
• Reject San Diego Gas and Electric Company’s (SDG&E’s) request that the Commission explicitly authorize Southern California Edison’s (SCE’s) “zig zag” methodology as a “middle ground” between the proportional allocation method and the waterfall method, because the zig zag method applied in practice is not proportional; • Reject as baseless Pacific Gas and Electric Company’s (PG&E’s) assertion of Commission error for failure to consider the record on various issues including that the waterfall inappropriately shifts financial risk to the community choice aggregators and that the waterfall treats bundled and unbundled customers inequitably; • Reject PG&E’s and SDG&E’s requests to establish a sunset date for the proportional allocation method, instead of the Proposed Decision’s order that the proportional allocation method will apply “unless and until the Commission determines otherwise”; and
• Reject SDG&E’s request for “flexibility” to mutually alter the payment allocation methodology through a joint advice letter with local community choice aggregators.

CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY COMMENTS

ON THE PROPOSED DECISION EXTENDING CURRENT PROPORTIONAL

ALLOCATION OF PAYMENT ON PAST-DUE BILLS BETWEEN INVESTOR-OWNED UTILITIES AND COMMUNITY CHOICE AGGREGATORS The California Community Choice Association (CalCCA) submits these reply comments pursuant to Rule 14.3 of the California Public Utilities Commission (Commission) Rules of Practice and Procedure1
to party opening comments on the proposed Decision Extending Current Proportional Allocation of Payment on Past-Due Bills Between Investor-Owned Utilities and Community Choice Aggregators2 (Proposed Decision), dated August 8, 2024.

I. INTRODUCTION
As noted in CalCCA’s Opening Comments, the Proposed Decision adopting the proportional allocation method for partial past due payments should be adopted. CalCCA addresses below the Opening Comments of Pacific Gas and Electric Company (PG&E) and San Diego Gas & Electric Company (SDG&E). Specifically, CalCCA recommends that the Commission:
• Reject SDG&E’s request that the Commission explicitly authorize Southern California Edison’s (SCE’s) “zig zag” methodology as a “middle ground” between the proportional allocation method and the waterfall method, because the zig zag method applied in practice is not proportional;
• Reject as baseless PG&E’s assertion of Commission error for failure to consider the record on various issues including that the waterfall inappropriately shifts financial risk to the community choice aggregators (CCA), and that the waterfall treats bundled and unbundled customers inequitably;
• Reject PG&E’s and SDG&E’s requests to establish a sunset date for the proportional allocation method, instead of the Proposed Decision’s order that the proportional allocation method will apply “unless and until the Commission determines otherwise”; and
• Reject SDG&E’s request for “flexibility” to mutually alter the payment allocation methodology through a joint advice letter with local CCAs. 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 Proposed Decision Extending Current Proportional Allocation of Payment on Past-Due Bills Between Investor-Owned Utilities and Community Choice Aggregators, Rulemaking (R.) 18-07-005 (Aug. 8, 2024). 2 II. SDG&E’S REQUEST FOR SCE’S ZIG ZAG TO BE AUTHORIZED IN PLACE

OF PROPORTIONAL ALLOCATION SHOULD BE REJECTED
The Commission should reject SDG&E’s request to authorize the use of the “zig zag” payment methodology instead of the proportional allocation method. The “zig zag,” previously used by SCE3 and authorized only for the term of the waterfall suspension in D.21-11-014,4 has turned out not to be
a “variation” of the proportional allocation method as SDG&E describes. 5 Instead, SCE’s application
of the zig zag in practice has resulted in a form of the waterfall. SCE has previously described the zig zag as creating “a payment posting priority that alternates payments between the investor-owned utility (IOU) and the CCA starting with the oldest arrearages a customer has.”6 On paper, the
“alternating” of payments appears to result in proportional payments over a period of time. In practice, however, SCE has devised a system in which its charges, within a billing cycle, are always older than the CCA charges, resulting in SCE always getting paid first. As described below, the zig zag in practice (1) is not proportional, (2) has a material negative impact on CCA financial stability, and (3) is overly complex from an operational standpoint. The Commission should reject SDG&E’s request to explicitly authorize the zig zag method in place of the proportional allocation method.

A. The Zig Zag Method in Practice Creates a Masked “Waterfall” to the IOUs and Should Not Be Allowed
SDG&E likely favors SCE’s zig zag because in practice it is not a proportional allocation methodology but rather results in a masked waterfall. Currently in SCE’s territory, if a customer continually makes on-time and complete payments, the zig zag approach is proportional because both SCE’s and the CCA’s charges are paid off in full. However, when customers are behind on their bills, make partial payments, or receive bills with multiple charges (due to delayed billing), the zig zag approach favors SCE as the funds are not distributed equally between SCE and the CCA. In these scenarios, the SCE charges are paid off first because SCE views these charges as older than the CCA charges. The reason SCE views their charges (for the same bill period) as being older than the CCA charges is because SCE reads the meter and is able to calculate the customer’s charges within 3 SCE did not file comments on the Proposed Decision, and therefore appears to support the Proposed Decision’s requirement that the IOUs use the proportional allocation method, instead of the zig zag or waterfall methods.
4 D.21-11-014, Decision Directing Allocation of Payment on Past-Due Bills Between Investor-Owned Utilities and Community Choice Aggregators, R.21-02-014 (Nov. 18, 2021). 5 SDG&E Opening Comments, at 1.
6 See Southern California Edison Company’s (U 338-E) Brief on Ruling Setting Joint Status Conference and Ordering Comments, R.17-06-024, R.21-02-014 (Aug. 27, 2021), at 3 (describing the zig zag method). 3 approximately one day, but the CCA must receive the usage from SCE before it can calculate the CCA charges and send them back to SCE to be presented on a bill. Because of the additional approximately two days for the CCA to receive the usage from SCE and return the CCA charges to SCE, SCE deems its charges as older and deprioritizes CCA charges for the same bill period.

SDG&E’s Appendix A provides an example of the zig zag that is not how the zig zag is currently applied in SCE’s territory. First, in any billing cycle, SDG&E assumes that the IOU charges and CCA charges are of the same age. However, in practice, the IOU calculates its portion of the bill first and then receives the CCA charges a day or more later. While the charges are on the same bill, for purposes of calculating which arrearage is paid first, the IOU’s charges are always the oldest. Second, SDG&E conveniently assumes that each arrearage payment is exactly fifty percent of the bill amount.

This means that for every other payment, the IOU and CCA will have collected one full past due bill.

This means that the percent of arrearage outstanding will align every other month.

In Appendix A attached hereto, CalCCA provides an example of how the zig zag actually works in SCE’s territory. Charges from the IOU are older than that of the CCA in each bill, and as is typical the amount paid is not exactly half of each past due bill. The result is that the amount in arrears after the first payment always demonstrates the IOU is paid first resulting in a lower percentage of arrears for the IOU. For comparison, Appendix A also includes the amounts paid to each entity when the true proportional allocation method is used. The comparison demonstrates that the zig zag is not analogous to the proportional allocation method, and should be rejected.

B. The Zig Zag Should be Rejected as it Has a Material Negative Impact on CCAs and is Operationally Complex to Implement and Manage
The zig zag method should be rejected given its material negative impact on CCAs. The zig zag is also overly complex to implement and manage from an operations standpoint. Given the magnitude of arrearages currently, both the IOUs and CCAs are anxious to receive even partial past due payments from customers in arrears. Compounding the arrearages are complexities in billing that have resulted recently in a large number of bills, especially in SCE’s territory, being delayed. The result is that customers receive large bills with amounts due from previous billing periods, which if paid only partially fall into the zig zag payment methodology. The zig zag in practice, like the waterfall as recognized in the Proposed Decision, “inappropriately shifts financial risk to the CCAs” and is not in the public interest given it prioritizes paying the IOUs first. In addition, as demonstrated in Appendix A, the zig zag is overly complex and difficult to manage from an operational standpoint, and is confusing to customers.
4 The Commission should reject SDG&E’s request to explicitly authorize SCE’s zig zag given that in practice it results in a masked waterfall, and does not result in proportional allocation of partial past due payments between the IOUs and CCAs.

III. PG&E’S ASSERTION OF COMMISSION ERROR FOR FAILURE TO

CONSIDER THE RECORD ON VARIOUS ISSUES IS BASELESS AND SHOULD

BE REJECTED
PG&E’s assertions of Commission error for failure to consider the record on various arguments advanced by PG&E, SDG&E, and The Public Advocates Office at the California Public Utilities Commission (Cal Advocates) are baseless and should be rejected. Specifically, PG&E states that the Proposed Decision fails to consider arguments by PG&E, SDG&E, and Cal Advocates before concluding that (1) the waterfall method inappropriately shifts financial risk to the CCAs, and (2) the proportional allocation method results in more equitable treatment of bundled and unbundled customers.
7 The Proposed Decision, however, spends nearly three pages summarizing party arguments.

The Proposed Decision also incorporates analysis from D.21-11-014 supporting temporarily suspending the waterfall method during the COVID pandemic on these exact topics, and then provides additional analysis supporting its conclusions.8 Given the Proposed Decision’s more than adequate analysis on these issues, PG&E’s assertions of error are simply a cover for its disagreement with the Commission’s conclusions, and should be rejected.

IV. PG&E’S AND SDG&E’S REQUESTS FOR THE PROPOSED DECISION TO

SPECIFY A SUNSET DATE FOR THE PROPORTIONAL ALLOCATION

METHOD SHOULD BE REJECTED
PG&E’s and SDG&E’s request for a sunset to the proportional allocation, instead of the Proposed Decision’s conclusion that the proportional allocation method be applied “unless and until the Commission determines otherwise,” should be rejected. Both PG&E and SDG&E claim that the Commission’s temporary allowance of the proportional allocation method in D.21-11-014 provides support for again establishing a sunset date. However, PG&E and SDG&E fail to note that the sunset established in D.21-11-014 was because the decision was issued in the COVID Proceeding, R.21-02-014, as a part of relief programs established to assist customers during the pandemic. It therefore made sense to align the timeframe for the proportional allocation with other relief programs, 7 PG&E Opening Comments, at 2-3.
8 See Proposed Decision, at 4-5 (allocation of risk between CCAs and customers), and 5-6 (equitable treatment of bundled and unbundled customers).
5 including the COVID-19 Payment Plans.9 Here, the Commission is finally addressing the need to indefinitely extend the proportional allocation method, without facing the unique circumstances to align the temporary relief provided in the COVID proceeding.10 The Proposed Decision’s finding that the proportional allocation method should continue until the Commission determines otherwise should therefore remain unchanged.

V. SDG&E’S REQUEST FOR “FLEXIBILITY” TO MUTUALLY ALTER THE

PAYMENT ALLOCATION METHODOLOGY THROUGH A JOINT ADVICE

LETTER WITH LOCAL CCAS SHOULD BE REJECTED
SDG&E’s request for “flexibility” to “negotiate the method of payment allocation that is best for customers and CCAs alike in the local service territory at some point in the future” and to allow updates to that payment allocation through a Tier 2 advice letter, should be rejected.11 Aside from the fact that CCAs in SDG&E’s service territory support the indefinite application of the proportional allocation method for all of the reasons advanced in the Proposed Decision, SDG&E’s request to relax the Commission’s directives once the Proposed Decision is adopted should be rejected. SDG&E should not be allowed to file a Tier 2 advice letter, whether “joint” or not, to gain “flexibility” with respect to that method.

VI. CONCLUSION
CalCCA appreciates the opportunity to submit these reply comments and requests adoption of the recommendations proposed herein.

Respectfully submitted,
Evelyn Kahl,
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
September 3, 2024
9 See D.21-11-014, at 1-2 (“During the pandemic, the Commission and Legislature directed electric utilities to suspend their standard practice of prioritizing payments first for the utility charges. Today’s decision extends the same direction to encompass all payments on outstanding bills through September 2024, the period equivalent to the duration of the COVID-19 Payment Plans.”). 10 PG&E Opening Comments, at 4; SDG&E Opening Comments, at 2-3. 11 See SDG&E Opening Comments, at 3.
t
Appendix A

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

THE PROPOSED DECISION EXTENDING CURRENT PROPORTIONAL

ALLOCATION OF PAYMENT ON PAST-DUE BILLS BETWEEN INVESTOR-OWNED

UTILITIES AND COMMUNITY CHOICE AGGREGATORS
Total IOU Balance CCA Balance IOU CCA IOU Balance CCA Balance Bill 1 (IOU Charges Calculated First) 150 100 100
Bill 1 (CCA Charges calculated second) 50 50
Bill 2 (IOU Charges Calculated First) 150 100 100
Bill 2 (CCA Charges calculated second) 50 50
Bill 3 (IOU Charges Calculated First) 150 100 100
Bill 3 (CCA Charges calculated second) 50 50
Beginning Balance 450 300 150 300 150
Percent of Bal. 100% 67% 33% 67% 33%
Payment 1 -80 -80 0 Bill 1 - $80 -53 -27
Balance 370 220 150 247 123
Percent of Bal. 100% 59% 41% 67% 33%
Payment 2 -80 -30 -50 Bill 1 - $20, Bill 2 - $10 Bill 1 - $50 -53 -27 Balance 290 190 100 193 97
Percent of Bal. 100% 66% 34% 67% 33%
Payment 3 -80 -80 0 Bill 2 - $80 -53 -27
Balance 210 110 100 140 70
Percent of Bal. 100% 52% 48% 67% 33%
Payment 4 -80 -30 -50 Bill 2 - $10, Bill 3 - $20 Bill 2 - $50 -53 -27 Balance 130 80 50 87 43
Percent of Bal. 100% 62% 38% 67% 33%
Payment 5 -80 -80 0 Bill 3 - $80 -53 -27
Balance 50 0 50 33 17
Percent of Bal. 100% 0% 100% 67% 33%
Payment 6 -50 0 -50 Bill 3 - $50 -33 -17
Ending Balance 0 0 0 0 0
Applied to Bill
Zig Zag Proportional Percent I Oldest charges are prioritized I I Payments are applied proportionally

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Establish
Energization Timelines.

R.24-01-018
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY COMMENTS ON THE

PROPOSED DECISION ESTABLISHING TARGET ENERGIZATION TIME PERIODS

AND PROCEDURE FOR CUSTOMERS TO REPORT ENERGIZATION DELAYS Evelyn Kahl,
General Counsel and Director of Policy
Leanne Bober,
Senior Counsel
Jennifer Baak
Senior Distribution Case Manager

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
1121 L Street, Suite 400
Sacramento, CA 95814
Telephone: (510) 980-9459
E-mail: [email protected]
September 4, 2024
FILED
09/04/24
04:59 PM
R2401018
i

TABLE OF CONTENTS
I. INTRODUCTION ...............................................................................................................1 II. THE IOUS’ REQUESTS TO LENGTHEN ENERGIZATION TARGETS AND TIMELINES IN MULTIPLE SCENARIOS SHOULD BE REJECTED ..................2 III. THE IOUS’ REQUESTS TO SUBMIT DATA ANNUALLY RATHER

THAN BIANNUALLY AND TO NARROW THE DATA REQUESTS
SHOULD BE REJECTED ...................................................................................................3 IV. THE COMMISSION SHOULD ADOPT SVCE’S REQUEST THAT THE

FINAL DECISION APPLY TO EXISTING ENERGIZATION PROJECTS
AND REJECT THE IOUS’ REQUESTS TO DELAY THE FINAL
DECISION’S EFFECTIVE DATE......................................................................................4 V. CONCLUSION ....................................................................................................................5 ii

SUMMARY OF RECOMMENDATIONS
The California Community Choice Association recommends that the California Public Utilities Commission:
• Reject Pacific Gas and Electric Company’s, Southern California Edison Company’s, and San Diego Gas & Electric Company’s (collectively, the IOUs) requests to lengthen energization targets and timelines in multiple scenarios; • Reject the IOUs’ recommendations to increase reporting frequency and narrow data reporting requirements; and
• Adopt Silicon Valley Clean Energy’s request to apply the final Decision to existing projects and reject the IOUs’ requests to delay the final Decision’s effective date.

CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY COMMENTS ON THE

PROPOSED DECISION ESTABLISHING TARGET ENERGIZATION TIME PERIODS

AND PROCEDURE FOR CUSTOMERS TO REPORT ENERGIZATION DELAYS The California Community Choice Association (CalCCA) submits these reply comments pursuant to Rule 14.3 of the California Public Utilities Commission (Commission) Rules of Practice and Procedure1
to party opening comments on the proposed Decision Establishing Target Energization Time Periods and Procedure for Customers to Report Energization Delays2 (Proposed Decision), dated August 12, 2024.

I. INTRODUCTION
Pacific Gas and Electric Company’s (PG&E), Southern California Edison Company’s (SCE), and San Diego Gas & Electric Company’s (SDG&E) (collectively, the IOUs) Opening Comments center around three requests: (1) lengthen the energization targets and timelines; (2) reduce the frequency of reporting and narrow the breadth of data required in the reporting; and (3) delay the effective date of the Proposed Decision’s energization requirements. The IOUs’ recommendations are in stark contrast to the requirements of AB 503
and SB 4104, as well as recommendations of
stakeholders in Opening Comments, to shorten energization targets and timelines and increase IOU energization responsibilities. The IOUs’ recommendations represent a “business as usual” approach that ignore the severe energization backlog threatening the state’s electrification and decarbonization goals.

The Legislature addressed the growing outcry of severely backlogged energization projects in SB 410 and AB 50, answering the urgent need to promptly energize customer facilities to support the state’s decarbonization goals. To serve the rapidly increasing load of electrified buildings and vehicles, the California Energy Commission forecasts a need for nearly 180 gigawatts of new generating capacity by 2040 to meet SB 1005
policy goals.6 The development of these new generating resources 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 Proposed Decision Establishing Target Energization Time Periods and Procedure for Customers to Report Energization Delays, Rulemaking (R.) 24-01-018 (Aug. 12, 2024). 3 Assembly Bill 50 (Stats. 2023, ch. 317) (AB 50).
4 Senate Bill 410 (Stats. 2023, ch. 394) (SB 410).
5 Senate Bill 100 (Stats. 2018, ch. 312) (SB 100).
6 2021 SB 100 Joint Agencies report, Figure 9 at 15:
https://efiling.energy.ca.gov/EFiling/GetFile.aspx?tn=237167&DocumentContentId=70349. 2 will come with significant costs. If the build-out of this new capacity outpaces the ability to energize new load, rates may increase and reaching the SB 100 goals will be at risk.

CalCCA supports the Proposed Decision, which sets a measured path toward requiring the IOUs to meet initial energization targets and timelines. At the same time, the Commission can collect data from the IOUs to uncover the root causes of the delays to refine the energization requirements in Phase 2. In response to Opening Comments, CalCCA recommends that the Commission:
• Reject the IOUs’ requests to lengthen energization targets and timelines in multiple scenarios;
• Reject the IOUs’ recommendations to increase reporting frequency and narrow data reporting requirements; and
• Adopt Silicon Valley Clean Energy’s (SVCE) request to apply the final Decision to existing projects and reject the IOUs’ requests to delay the final Decision’s effective date.

II. THE IOUS’ REQUESTS TO LENGTHEN ENERGIZATION TARGETS AND

TIMELINES IN MULTIPLE SCENARIOS SHOULD BE REJECTED
IOU recommendations to lengthen energization targets and timelines for various scenarios ignore the current energization delays that sparked AB 50 and SB 410, and should be rejected. PG&E, SCE, and SDG&E each argue for increased timelines,
7 while many stakeholders go the opposite
direction and recommend that the Proposed Decision be modified to shorten the targets and timelines.8 CalCCA agrees with the middle ground approach in the Proposed Decision to moderately reduce the compliance targets and timelines in Phase 1, without penalties at this point for the IOUs’ failure to comply. The Phase 1 targets and timelines, coupled with the expeditious collection of robust data, can adequately inform refinement of the targets and timelines in Phase 2. Unfortunately, instead of diving in to remedy the energization emergency through their best efforts in Phase 1, the IOUs remain singularly focused on their perceived inability to meet the proposed targets and timelines. If the Phase 1 data demonstrates that the IOUs are correct that any of the scenarios they have raised should be carved out of the target or timeline because they are indeed outside of IOU control, the Commission can do that in Phase 2 after analyzing the data with stakeholder input. The Proposed Decision strikes a balance for Phase 1 between establishing initial targets and timelines without penalizing the IOUs for 7 PG&E Opening Comments, at 1-3, 6-8; SCE Opening Comments, at 2-6; SDG&E Opening Comments, at 8-14.
8 Advanced Energy United Opening Comments, at 1-3; CALSTART Opening Comments, at 2-5, 10-13; Interstate Renewable Energy Council Opening Comments, at 1-6, 8-12; Powering America’s Commercial Transportation Opening Comments, at 4.
3 failure to comply. The IOUs’ requests to lengthen energization targets and timelines are therefore unnecessary and should be rejected.

III. THE IOUS’ REQUESTS TO SUBMIT DATA ANNUALLY RATHER THAN

BIANNUALLY AND TO NARROW THE DATA REQUESTS SHOULD BE

REJECTED
IOU recommendations to change the Proposed Decision’s data reporting frequency and narrow the categories of data to be collected should be rejected. PG&E, SCE, and SDG&E all recommend annual, rather than biannual, reporting, arguing that increased reporting frequency is burdensome, excessive, costly, and not required by either AB 50 or SB 410.9 They further recommend limiting the magnitude of data to be collected, stating they lack the ability to collect much of the data listed in Appendix B of the Proposed Decision, and that doing so will divert resources from energizing customers.10
First, the IOUs recommend modifying the biannual reporting frequency to annually. While annual reporting may become sufficient after the Commission establishes its refined energization targets in Phase 2, more frequent reporting is necessary immediately to inform Phase 2. In fact, the Phase 2 schedule has party opening briefs on Phase 2 issues due in March 2025, and a Phase 2 Decision is scheduled to be issued in the third quarter of 2025.11 Without quarterly reporting as CalCCA recommends in Opening Comments,12 data will not be available in time to inform the Phase 2 proceedings. The Commission should therefore reject the IOUs’ requests and require the IOUs to report quarterly on the Appendix B data.

Second, the IOUs’ requests to narrow the data required by Appendix B should be rejected.

Information from the Appendix B reporting is necessary to accurately refine the targets and timelines in Phase 2. As noted in the Proposed Decision, the data provided by the IOUs in response to the ALJ Rulings was incomplete, and uncovered the need for increased reporting and monitoring to accurately set the targets:

We find that the information provided by the large electric IOUs to date is inadequate to support full implementation of Pub. Util. Code § 933.5(a)(2)(B). While the large electric IOUs collected some of the data necessary to evaluate timeliness of customer energization 9 PG&E Opening Comments, at 5; SCE Opening Comments, at 8; SDG&E Opening Comments, at 2. 10 PG&E Opening Comments, at 5; SCE Opening Comments, at 8; and SDG&E Opening Comments, at 1. 11 Assigned Commissioner’s Scoping Memo and Ruling, R.24-01-018 (Mar. 28, 2024), at 9. 12 See CalCCA Opening Comments, at 10.
4 requests, there are many gaps that must be addressed to ensure statutory compliance.13
The IOUs cite the costs, staffing, and effort required to answer the data requests.14 SDG&E even tries to entice the Commission to accept a “benefit” of narrowing the Appendix B requirements to “reduce[] the amount of data [for Energy Division staff] to analyze, thereby reducing workload and associated costs.”15 SDG&E misses the mark and its (and the other IOUs’) recommendations are the exact opposite of what is needed – accurate, robust data to uncover the root causes of the extreme energization delays and to set accurate and accelerated targets.

The IOUs’ requests to set annual and narrowed requirements for IOU reporting should be rejected. Instead, the Commission should adopt CalCCA’s request for Appendix B quarterly reporting.16 IV. THE COMMISSION SHOULD ADOPT SVCE’S REQUEST THAT THE FINAL

DECISION APPLY TO EXISTING ENERGIZATION PROJECTS AND REJECT THE IOUS’ REQUESTS TO DELAY THE FINAL DECISION’S EFFECTIVE DATE The Commission should adopt SVCE’s recommendation to apply the final Decision’s requirements to existing projects that began the energization process before the targets were adopted.17 SVCE’s recommendation makes sense, to ensure pending energization projects benefit from the new targets and timelines and to obtain data regarding those projects. CalCCA provides similar requests for energization data for all pending energization projects in its Opening Comments.18 The Commission should also reject the IOUs’ recommendations to delay the effective date of the final Decision’s requirements, which will delay obtaining data on the root causes of the energization backlog and worsen the energization crisis. The IOUs’ recommendations include delaying the customer engagement requirements to allow additional time to develop processes and train staff.
19 SDG&E, seemingly ignoring the emergency energization delay situation, calls the Proposed Decision’s requirement for the targets to take effect immediately “flawed,” stating that 13 Proposed Decision, at 47 (emphasis added).
14 PG&E Opening Comments, at 5; SCE Opening Comments, at 7-8; SDG&E Opening Comments, at 1-3. 15 SDG&E Opening Comments, at 3.
16 See CalCCA Opening Comments, at 10.
17 See SVCE Opening Comments, at 7 (“The Proposed Decision does not explain [its requirements’] applicability to projects that may have already initiated contact with the IOU or gone through several steps in the energization process. The applicability to this type of project should be retroactive, meaning that a project that began the energization process before the targets were adopted but has not been energized for longer than the applicable maximum energization timeline would indicate lack of compliance by the IOUs.”). 18 See CalCCA Opening Comments, at 5-8.
19 PG&E Opening Comments, at 3.
5 “from a legal perspective, nothing in SB 410 mandates an immediate or hasty implementation of the energization targets or reporting requirements.”20 Therefore, SDG&E appears to believe that mere implementation of the target energization time periods required by SB 410 by September 30, 2024, is sufficient from a “legal perspective.” The legislative history of SB 410 and AB 50 belie SDG&E’s interpretation of the urgency:
[D]elays for connecting electric vehicle fast chargers were around 70 weeks in PG&E territory in 2022. The slow connection of critical climate appliances and resources could inhibit California’s targets to decarbonize buildings and clean the grid. This legislation requires the PUC to improve existing delays in interconnections, as well as plan for future ones.21
The legislative history also states:

Severe electric interconnectivity delays have become the everyday reality of utility customers in California. In just one county located in [the bill author’s] district, over 30 customers were told they would have to wait over 10 years for their lights to be turned on. This is unacceptable and alarming here in California, where we have set some of the most ambitious climate goals in the world. Currently, families and business-owners are being asked pay significant planning fees – up to hundreds of thousands of dollars – upon receiving “Will Serve” letters provided by utilities. As it turns out, “Will Serve” really means “Will Serve Eventually.” As we strive to advance housing development, expand business, and meet our climate change goals, we have to get serious about the realities of electrification.
22 The Proposed Decision correctly captures the legislative intent, stating “it is imperative that utilities begin planning and aiming to achieve these targets now.”23 The Commission should reject the IOUs’ recommendations to delay the effective date for implementation of the energization requirements.

V. CONCLUSION
CalCCA appreciates the opportunity to submit these reply comments and requests adoption of the recommendations proposed herein.
20 21
22 SDG&E Opening Comments, at 4.

California Senate Committee on Energy, Utilities and Communications, SB 410 (Mar. 13, 2023), at 8.

California Assembly Utilities and Energy Committee, Assembly Appropriations Committee, AB 50 (Wood) Assembly Third Reading, as amended (May 18, 2023), at 2. 23 Proposed Decision, at 62 (emphasis added).
6 Respectfully submitted,
Evelyn Kahl,
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
September 4, 2024
t

MCE Board of DirectorsSeptember 19, 2024

MCE Board of Directors
September 19, 2024