Regulatory Packet Part 1 — MCE Board of Directors, November 20, 2025

SEPTEMBER FILINGS
Docket No.: Application 25-02-013
Exhibit No.:

Date: September 15, 2025
Witness: Brian Dickman

PREPARED DIRECT TESTIMONY OF BRIAN DICKMAN

ON BEHALF OF

THE CALIFORNIA COMMUNITY CHOICE ASSOCIATION
IN PACIFIC GAS AND ELECTRIC COMPANY’S
2024 ERRA COMPLIANCE PROCEEDING

PUBLIC VERSION
i
Table of Contents
I. INTRODUCTION AND SUMMARY OF TESTIMONY ...................................................... 1 II. BACKGROUND ON THE PCIA AND PABA ....................................................................... 3 A. Background on the PCIA .................................................................................................... 3 B. Calculation of the PCIA revenue requirement .................................................................... 4 C. Customer vintaging and allocation ..................................................................................... 7 D. ERRA Compliance Cases ................................................................................................... 7 III. PG&E SHOULD CORRECT THE RETAINED RA CREDIT TO PABA TO INCLUDE

THE VALUE OF ALL CAPACITY WITHHELD FROM THE MARKET FOR ITS OWN USE ........................................................................................................................................ 8 A. Operational Constraints and Portfolio Reserves, as defined in PG&E’s BPP, are Retained RA ....................................................................................................................................... 9 B. The Operational Constraints used to determine Retained RA in the PABA are inconsistent with the Operational Constraints approved by the Commission and specified in PG&E’s BPP. ................................................................................................................ 13 C. PG&E should correct its Retained RA accounting for 2024 to match the Operational Constraints held back in its RA solicitations. ................................................................... 16 IV. PG&E SHOULD FILE SUPPLEMENTAL TESTIMONY DEMONSTRATING CUSTOMER VINTAGING ASSIGNMENTS ARE CORRECT ....................................... 17 A. PG&E’s internal audit raised concerns over customer vintaging assignments. ................ 17 B. PG&E should file supplemental testimony once the analysis of the customer vintaging issue has been completed. ................................................................................................. 19 V. PG&E DID NOT CREDIT PABA FOR EXCESS RA USED TO MEET ITS SYSTEM RELIABILITY INCREMENTAL PROCUREMENT TARGET IN OCTOBER 2024 ...... 20 Attachments
Attachment A: Curriculum Vitae of Brian Dickman
Attachment B: PG&E Responses to CalCCA Data Requests
1 1 I. INTRODUCTION AND SUMMARY OF TESTIMONY
2 The California Community Choice Association (CalCCA) presents this direct 3 testimony in the Application of Pacific Gas and Electric Company (PG&E) for 4 Compliance Review of Utility Owned Generation Operations, Portfolio Allocation 5 Balancing Account (PABA) Entries, Energy Resource Recovery Account (ERRA) Entries, 6 Contract Administration, Economic Dispatch of Electric Resources, Utility Owned 7 Generation Fuel Procurement, and Other Activities for the Record Period January 1 8 Through December 31, 2024 (Application). This testimony has been prepared on behalf 9 of CalCCA by Brian Dickman, Partner, NewGen Strategies and Solutions, LLC. Mr. 10 Dickman’s qualifications are set forth in Attachment A. 11 CalCCA has a particular interest in the PABA, which is charged to CalCCA 12 members’ customers through the Power Charge Indifference Adjustment (PCIA) rates. 13 This testimony presents CalCCA’s recommendations on issues falling within scope of the 14 following items from the Assigned Commissioner’s Scoping Memo and Ruling in this case:1 15
16 1. Whether PG&E, during the record period, prudently administered and 17 managed the following, in compliance with all applicable rules, regulations 18 and Commission decisions, including but not limited to Standard of Conduct 19 No. 4 (SOC 4):
20 A. Utility-Owned Generation (UOG) Facilities, including for the 2023 21 Belden and Caribou 1 Powerhouse outages and two 2023 Diablo 22 Canyon Power Plant maintenance outages;
23 B. Qualifying Facilities (QF) Contracts; and
24 C. Non-QF Contracts.
1 Assigned Commissioner’s Scoping Memo and Ruling, Application (A.) 25-02-013 (May 2, 2025) (Scoping Ruling), at 2-3.
2 1 If not, what adjustments, if any, should be made to account for imprudently 2 managed or administered resources?
3 3. Whether the entries recorded in the ERRA and PABA are reasonable, 4 appropriate, accurate, and in compliance with Commission decisions; 5 5. Whether PG&E administered Resource Adequacy (RA) procurement and sales 6 consistent with its Bundled Procurement Plan (BPP), including whether 7 PG&E made reasonable attempts to sell excess RA consistent with its BPP. 8 Based on my review of PG&E’s Application, supporting workpapers, and 9 responses to discovery, I make the following findings and recommendations:
10 • Error Related to 2024 Retained RA in the PABA: The Operational 11 Constraints PG&E recognized as Retained RA in the PABA are inconsistent 12 with the Operational Constraints approved by the Commission and specified in 13 PG&E’s BPP. PG&E should recategorize RA capacity related to the approved 14 Operational Constraints by reducing Unsold RA and increasing Retained RA. 15 • Error Related to Customer Vintaging: PG&E should be required to file 16 supplemental testimony in this proceeding detailing how its programming logic 17 used for assigning customer vintages complies with the requirements of Decision (D.) 16-09-044 2 18 for all community choice aggregator (CCA) 19 customers and detailing the extent and impact of an issue identified for 20 customers moving to a new address after opting out of and then back into CCA 21 service.
22 • Error Related to PABA Entries Associated with Transfer of Excess RA:
23 PG&E disclosed that it did not credit PABA for the value of the excess RA used 2 D.16-09-044, Decision Resolving Vintaging Methodology for Power Charge Indifference Adjustment for Community Choice Aggregation Customers, A.14-05-024 (Sept. 29, 2016). 3 1 to meet its incremental system reliability procurement targets in October 2024. 2 Through discovery PG&E confirmed that it made a correction in April 2025 by 3 crediting the PABA for the value of the October excess RA, plus the associated 4 interest. The Commission should approve this correction to PG&E’s record 5 year accounting entries.
6 II. BACKGROUND ON THE PCIA AND PABA
7 A. Background on the PCIA
8 CCA customers receive generation services from their local CCA, and receive 9 transmission, distribution, billing, and other services from the incumbent for-profit utility. 10 CCA customers pay CCA-specific generation rates. CCA rates vary and are partially 11 influenced by local mandates to procure and maintain clean electricity portfolios that, in 12 many cases, exceed state requirements for renewable generation. In addition, CCA and 13 other unbundled customers are subject to several non-bypassable charges (NBC), including 14 the PCIA and the Cost Allocation Method (CAM) surcharge. 15 The Commission has an obligation to ensure “indifference,” meaning when 16 customers of investor-owned utilities (IOUs) depart from bundled service and receive their 17 electricity from a non-IOU provider, such as a CCA, “those customers remain responsible for costs previously incurred on their behalf by the IOUs — but only those costs.”3 18 The 19 PCIA is the tool the Commission adopted “intend[ing] to equalize cost sharing” between these two groups of customers.4 20
3 Scoping Memo and Ruling of Assigned Commissioner, Rulemaking (R.) 17-06-026 (Sept. 25, 2017), at 2; see also D.18-10-019, Decision Modifying the Power Charge Indifference Adjustment Methodology, R.17-06-026 (Oct. 11, 2018), at 3.
4 See D.18-10-019, at 3.
4 1 B. Calculation of the PCIA revenue requirement
2 The PCIA revenue requirement is also known as the Indifference Amount. The 3 Indifference Amount is the difference between the cost of the IOU’s supply portfolio and 4 the market value of the IOU’s supply portfolio as demonstrated in Figure 1:
5 FIGURE 1
6 7 Utility Portfolio Costs include:
8 (i) the cost for UOG (i.e., the capital investment recovery and fixed 9 maintenance costs the Commission sets in a General Rate Case (GRC)); 10 (ii) purchased power such as that from power purchase agreements (PPA); 11 (iii) fuel costs for UOG and PPAs with tolling agreements; and 12 (iv) California Independent System Operator (CAISO) grid charges and revenues, net of any sales.5 13
14 Portfolio Market Value (PMV) is derived from total eligible resource output 15 multiplied by the Market Price Benchmarks (MPB), an administratively determined set of proxy values that are intended to estimate the market value of the IOU’s resource portfolio.6 16 17 PMV consists of three principal components: Energy Value, Renewables Portfolio 18 Standard (RPS) Value, and RA Value:
5 D.11-12-018, Decision Adopting Direct Access Reforms, R.07-05-025 (Dec. 1, 2011), at 8-9. 6 D.19-10-001, Decision Refining the Method to Develop and True Up Markey Price Benchmarks, R.17-06-026 (Oct. 10, 2019), at 6 (“Market Value is the estimated financial value, measured in dollars, that is attributed to a utility portfolio of energy resources for the purpose of calculating the Power Charge Indifference Adjustment for a given year.”).
5 1 • Energy Value is the financial value, measured in dollars, that is attributed to the generation component of a utility portfolio for a given year;7 2 3 4 • RPS Value is the financial value, measured in dollars, that is attributed to the 5 renewable energy component of a utility portfolio for a given year above and beyond the Energy Value;8 6 and
7 8 • RA Value is the financial value, measured in dollars, that is attributed to the RA component of a utility portfolio for a given year.9 9
10 11 MPBs are estimates of the value per unit (not total portfolio value) associated with 12 the three principal sources of value in utility portfolios (non-RPS energy, RPS, and RA capacity).10 13 Each MPB must be multiplied by the relevant portfolio volume as part of the overall calculation of Portfolio Market Value:11 14
15 • Energy Index is the MPB that reflects the estimated market value of each unit 16 of energy in a utility portfolio, in dollar value per megawatt hour ($/MWh). It 17 is sometimes referred to as “Brown Power Index,” “Brown Power component,” “Brown Power Adder,” or “Brown Power benchmark”;12 18
19 20 • RPS Adder is the MPB that reflects the estimated incremental value of each unit of RPS-eligible energy in $/MWh;13 21
22 23 • RA Adder is the MPB that reflects the estimated value of each unit of capacity 24 in a utility portfolio that can be used to satisfy RA obligations, in dollar value 25 per kilowatt ($/kW-month).
26 PCIA revenue requirement is initially estimated in each utility’s annual ERRA 27 Forecast case using forecasted Utility Portfolio Costs and forecasted Portfolio Market 28 Value. The forecast Portfolio Market Value calculation is shown in Figure 2 below:
7 Ibid. 8
Ibid. 9
Ibid. 10 Ibid. 11 Ibid. 12 Id., at 7.
13 Ibid.
6 1 FIGURE 2
2 3 The forward-looking, forecasted ingredients of total portfolio cost and value are netted to 4 produce the Indifference Amount portion of the PCIA revenue requirement. 5 After the conclusion of each year, each utility files an annual ERRA Compliance 6 case to seek approval of the Indifference Amount “true up” recorded to the PABA. This 7 “true up” modifies the forecasted PCIA revenue requirement from the prior year to reflect, 8 among other things, actual revenues received for products sold from the portfolio and to 9 reflect a zero-dollar value for products left unsold from the portfolio. The revenue 10 requirement modification also updates the proxy market values for products the utilities 11 used to serve bundled customers, changing the forecast energy, RPS, and RA MPBs to 12 final energy, RPS, and RA MPBs. This “true-up” relies on the same methodology used for 13 the forecast and determines the final portfolio value, as shown in Figure 3 below:
14 FIGURE 3
15 16 Prior to D.18-10-019, the PCIA rate was set only on a forecast basis with no after-the-fact 17 adjustment to the forecasted PCIA revenue requirement for unbundled customers. Decision 18 18-10-019 approved such an adjustment via the PABA, a rolling balancing account tracking 19 the difference between costs and revenues used to determine the forecasted PCIA revenue 7 1 requirement and the actual costs and revenues PG&E realizes during the year related to its 2 PCIA-eligible resource portfolio.
3 C. Customer vintaging and allocation
4 Each PCIA-eligible generation resource and customer is assigned a “vintage.” A 5 distinct portfolio of generation resources is identified for each vintage year based on when 6 a commitment to procure each resource was made. Customers are assigned to vintage years according to the date the customer departed bundled IOU service.14 7 Customers continuing 8 to receive bundled service from the IOU are included in the latest vintage. Each vintage is assigned a separate PCIA revenue requirement15 9 and customers are responsible for the 10 cumulative PCIA revenue requirement for years prior to and including their vintage. The 11 PCIA revenue requirement is allocated among both bundled and unbundled customers based on their vintage16 12 and their rate class using the allocation factors from the most recently approved GRC.
17 13
14 D. ERRA Compliance Cases
15 In the ERRA Compliance case, the Commission considers the accounting entries 16 PG&E made to its various procurement-related balancing accounts (including the PABA) 17 in the prior year (i.e., in this case, in 2024), to ensure those entries comply with 18 Commission rules and decisions. This backward-looking review is an important step in the 19 ERRA process because it serves to ensure that the utility’s accounting entries, and 20 consequently, its rates, indeed achieved indifference consistent with the objective of the 14 Unlike portfolio resources, customers are assigned to vintages using a July to June calendar period.

For example, customers departing bundled service between July 2019 and June 2020 are assigned to the 2019 vintage.
15 D.11-12-018, at 9.
16 Ibid. 17 D.18-10-019, at 122 and Ordering Paragraph (OP) 4. 8 1 PCIA framework. To the extent PG&E’s calculation of its PCIA revenue requirement, or 2 allocation of that revenue requirement to vintages and rate classes, or other entries, did not 3 comply with Commission decisions, the Commission must direct corrections through its 4 Order in the ERRA Compliance case to ensure customers are not harmed. 5 Below, I discuss certain issues in PG&E’s Application related to its entries to the 6 PABA for record year 2024, as well as customer vintaging. 7 III. PG&E SHOULD CORRECT THE RETAINED RA CREDIT TO PABA TO 8 INCLUDE THE VALUE OF ALL CAPACITY WITHHELD FROM THE
9 MARKET FOR ITS OWN USE
10 RA Value provided by PCIA-eligible resources is an important offset to costs 11 recorded to the PABA during the record year. The Commission established a methodology 12 for calculating RA Value in D.19-10-001, based on the inputs for price and quantity terms listed in the table below:18 13
14 15 As shown in the table above, PG&E is required to record the value of RA in three 16 categories:
18 D.19-10-001, Attachment B, Table IV.
9 1 1. Actual Retained RA: RA used for compliance and retained for IOU use, 2 valued using the RA Adder MPB;
3 2. Actual Sold RA: RA sold to third parties, valued at the actual transacted 4 prices; and
5 3. Actual Unsold RA: RA offered for sale but not sold or used by the IOU, 6 valued at $0.
7 Because PG&E’s Retained RA, Sold RA, and Unsold RA directly contribute to 8 PCIA portfolio value, accurate accounting is essential to avoid unjust and unnecessary 9 impacts to customers. For example, understating the amount of Retained RA can result in 10 higher quantities of Unsold RA and increase the above-market costs that will be recovered 11 from customers through PCIA rates. Consistent with D.19-10-001, any RA that PG&E 12 withheld from the market and used for PG&E’s own purposes should be valued as Retained 13 RA and accounted for as such in the PABA.
14 A. Operational Constraints and Portfolio Reserves, as Defined in PG&E’s BPP, 15 are Retained RA
16 According to PG&E, the utility endeavors to sell all excess RA capacity to the extent it is available.19 17 Appendix S of PG&E’s BPP details that the System RA capacity 18 offered for sale in each RA solicitation
19 20
21 22
19 PG&E response to CalCCA data request 1.06.
20 See PG&E’s Bundled Procurement Plan, Appendix S, Section B.3.b.1.a. 10 1
2 3
4 5 PG&E creates a projected RA position at the time it holds each solicitation in order 6 to determine the quantity of RA available for sale at that point in time. As part of the Joint 7 CCA Master Data Request included with PG&E’s filing in this case, PG&E provided 8 CalCCA the RA positions it prepared for each solicitation in which it offered to sell RA with delivery during 2024.21 9 Table 1 below summarizes each of these System RA position 10 reports, showing the available RA capacity, RA requirements, and other adjustments that 11 reduce the capacity offered for sale pursuant to PG&E’s BPP. 21 PG&E response to Joint CCA Master Data Request 1.08, attachment 2.

12 22 1 PG&E explains that Operational
2 Constraints is defined as
3 23 4 Since the capacity held back
for Portfolio Reserves and Operational Constraints is not offered for sale to the market,24 5 6 it cannot be considered Sold RA or Unsold RA; rather, consistent with D.19-10-001 this 7 capacity must be valued as Retained RA in the PABA.
8 Based on PG&E’s responses to discovery, it appears PG&E agrees that capacity 9 held back for Portfolio Reserves and Operational Constraints should be valued as Retained 10 RA in the PABA. When asked in discovery whether PG&E recorded the Portfolio Reserves 11 and Operational Constraints RA capacity as Retained, Sold, or Unsold RA, PG&E 12 responded that both were recorded to PABA as Retained RA as calculated in its 2024 RA 13 Tracker workpaper. PG&E explained that its RA Tracker, the file used to calculate and 14 record the value of Retained RA, includes the Portfolio Reserves as an increase to the RA Compliance requirement used to determine the amount of Retained RA in 2024.25 15 PG&E 16 further explained that Operational Constraints are shown in the RA Tracker as a “derate” 17 that reduces available RA capacity in the RA Tracker, and the derate quantity is also counted as Retained RA in 2024.26 18 However, as I explain below, the derate quantity in the 19 RA Tracker does not match the amount of RA capacity held back as Operational 20 Constraints in PG&E’s RA solicitations. As a result, PG&E’s recorded Retained RA value 22 PG&E response to CalCCA data request 1.16. 23 Ibid.
24 PG&E response to CalCCA data request 1.17. 25 PG&E response to CalCCA data request 1.19. 26 PG&E response to CalCCA data request 1.18.

16 1 C. PG&E Should Correct its Retained RA Accounting for 2024 to Match 2 the Operational Constraints Held Back in its RA solicitations 3 PG&E should have calculated Retained RA in its 2024 RA Tracker using the 4 Operational Constraints that were approved by the Commission and held back from the 5 market in PG&E’s RA solicitations. To correct the 2024 PABA accounting, PG&E should 6 increase Retained RA and reduce Unsold RA for the months when the recorded Operational 7 Constraints were less than the approved Operational Constraints (and vice versa). 8 However, the monthly adjustments will be limited by the amount of Unsold RA remaining in each month.29 9 Table 5 below shows the adjustment required each month to recategorized 10 RA capacity from Unsold RA to Retained RA to reflect additional Operational Constraints. 11 Table 5: Recategorized RA by Month
12 13 While Operational Constraints used to determine Retained RA should be equal to the 14 Operational Constraints approved in the BPP and held back in the RA solicitations, 29 The quantity of Unsold RA remaining each month is affected by other moving pieces in the RA calculation such as actual available capacity from resources, actual outages, etc. !"#$%"&'()*"+ !- .$/$#)%0 $1+ 2$34"
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17 1 CalCCA’s recommended adjustment accounts for the fact PG&E should also not have a 2 negative Unsold RA amount in any month. CalCCA’s recommended adjustment increases 3 Retained RA by which has a total value of based on the 4 System RA Adder of Like other Retained RA, the recategorized RA 5 value should be credited to the PABA with an offsetting debit to the ERRA, plus the 6 associated prior period interest.
7 IV. PG&E SHOULD FILE SUPPLEMENTAL TESTIMONY DEMONSTRATING 8 CUSTOMER VINTAGING ASSIGNMENTS ARE CORRECT
9 A. PG&E’s Internal Audit Raised Concerns Over Customer Vintaging 10 Assignments
11 In the record year 2024, PG&E finalized an internal audit of its PCIA customer 12 vintaging, which reviewed PG&E’s processes and controls over assigning customers into vintages for the purpose of assessing PCIA charges.30 13 The audit had two main findings 14 with recommended corrective actions: (1) PG&E should improve its documentation to 15 support customer vintage assignments and (2) PG&E should assign ownership over the 16 programming logic used in its billing system to assign vintages and track unique vintages 17 for customers as needed. During the audit, PG&E was unable to locate documentation to 18 support the accuracy of the vintaging assignments for 3 percent of the 200 sampled customers.31 19 In some instances, the internal audit had to review CCA implementation 20 plans, news articles, and CCA websites to determine the reasonableness of vintages in the sample.32 21 The PG&E internal audit also raised the possibility of incorrect programming 22 logic that did not track unique vintages for certain customers as required by D.16-09-044. 30 PG&E Prepared Testimony, at 12-26, line 18 through page 12-27, line 16. 31 Id., at 12-27, Footnote 57; see also PG&E response to CalCCA data request 3.06. 32 PG&E response to CalCCA data request 1.29.
18 1 In response to the audit, PG&E assigned responsibility for documenting CCA 2 vintage assignment to its Community Vitality team and established a process to preserve correspondence and information from CCAs supporting vintage assignment.33 3 PG&E also 4 assigned its Revenue Controls & Policy team to ensure the billing system programming 5 logic, which determines customer vintages, is aligned with the requirements of D.16-09- 044.34 6 Through discovery, PG&E acknowledged there is an issue with the programming logic for assigning vintages to a certain set of customers.35 7 8 According to D.16-09-044, there are three different methods to assign vintages 9 based on when the customer joined a CCA: (1) initially, a customer is assigned a vintage 10 according to the default vintage of the CCA service territory, which is based on the date the territory was phased into CCA service;36 11 (2) if a customer moves from one CCA 12 territory to another CCA territory that has a different vintage, the customer’s vintage is updated to match the default vintage of that new CCA territory;37 13 and (3) customers who 14 affirmatively opt out of CCA service and then opt back into CCA service at a later time are 15 to be assigned an individual vintage associated with the date they depart from bundled service and not the default vintage of the CCA territory.38 16 17 PG&E states that its current vintaging logic is consistent with D.16-09-044 for the 18 first two groups of customers: the (1) initial vintage assignment and (2) for customers that 19 move from one CCA service territory to another CCA service territory. Specifically, a 20 customer is assigned the default vintage of the CCA territory, and the customer’s vintage 33 PG&E response to CalCCA data request 1.31 and 3.07. 34 PG&E response to CalCCA data request 1.32. 35 PG&E supplemental response to CalCCA data request 1.30. 36 D.16-09-044, at 14-15.
37 Id., at 15.
38 Id., at 15 and OP 5.
19 is updated to the new CCA territory default vintage if the customer moves.39 1 The flaw 2 within PG&E’s current programming logic—which PG&E acknowledges—arises with the 3 third group of customers: when a CCA customer affirmatively opts out of CCA service, 4 then opts back into CCA service at a later date, and subsequently moves to a new address 5 within CCA territory. PG&E’s current programming logic resets a customer’s vintage to 6 the default vintage of the CCA territory each time a CCA customer moves to a new address.40 7 However, per the logic set forth in D.16-09-044, customers who have opted back 8 into CCA service should be assigned the vintage associated with the date they departed 9 bundled service, and they should not be re-assigned the default vintage of the CCA when 10 they relocate to another address in CCA territory. Consequently, under PG&E’s existing 11 logic, certain customers are being incorrectly vintaged, which means those customers have 12 been incorrectly billed.
13 B. PG&E Should File Supplemental Testimony Once the Analysis of the 14 Customer Vintaging Issue Has Been Completed
15 In discovery, PG&E indicated that it is still working to determine the number of 16 customers moving within a CCA that have been incorrectly vintaged as well as the 17 estimated cost and schedule to update the programming logic. PG&E expects to finalize this determination by the end of Q4 2025.41 18
19 CalCCA recommends that the Commission require PG&E to file supplemental 20 testimony in this proceeding detailing how its programming logic used for assigning 21 customer vintages complies with the requirements of D.16-09-044 for all CCA customers 22 and detailing the extent and impact of the issue identified for customers moving after opting 39 PG&E response to CalCCA data request 3.09.
40 Ibid. 41 PG&E supplemental response to CalCCA data request 1.30. 20 1 into CCA service. In the supplemental testimony, PG&E should demonstrate that its 2 programming logic is properly assigning the default vintage of the CCA for any customers 3 moving to a CCA territory, assigning the default vintage of the CCA in a customer’s new 4 location when they move from one CCA territory to another, assigning a specific vintage 5 for customers that opt-out of CCA service for a period and ultimately opt back in to CCA 6 service, and assigning a specific vintage and keeping that vintage for customers who opt-7 out of CCA service before opting back in to CCA service and moving addresses within a 8 CCA territory. PG&E should also be required to provide the detailed impact of 9 programming logic errors, including the following:
10 • The magnitude of the vintaging issues in terms of number of customers 11 impacted and billing correction amount by CCA territory and by vintage. 12 • The required correction to PCIA revenue recorded to PABA. 13 • The required programming fix to the vintaging logic and the associated 14 costs with making this fix.
15 • Timeline for when the vintage programming logic will be fixed. 16 • How PG&E intends to address billing corrections in terms of customer 17 refunds and/or back-billed charges to customers.
18 Parties, including CalCCA, should have the opportunity to review PG&E’s supplemental 19 testimony and provide their own testimony in response. 20 V. PG&E DID NOT CREDIT PABA FOR EXCESS RA USED TO MEET ITS 21 SYSTEM RELIABILITY INCREMENTAL PROCUREMENT TARGET IN 22 OCTOBER 2024
23 In its Prepared Testimony, PG&E reports it transferred a total of excess 24 RA capacity from its existing PCIA-eligible resource portfolio to CAM portfolio to be 21 1 counted toward its 2024 System Reliability Incremental Procurement requirement established in D.21-03-056.42, 43 Pursuant to D.21-12-015,44 2 PG&E is authorized to count 3 excess RA capacity from existing resources to meet its System Reliability Incremental 4 Procurement targets, provided it has first made reasonable attempts to sell this excess capacity to other load-serving entities.45 5 Because cost recovery for System Reliability 6 Incremental Procurement is through the CAM, the value of excess RA capacity provided 7 by existing resources must be transferred from the applicable balancing account to the 8 CAM balancing account (for PG&E, the New System Generation Balancing Account 9 (NSGBA)). PG&E reports that it counted of excess RA from existing PCIA-eligible resources during the months of June through October of 2024.46 10 The monthly 11 amount of excess RA used from existing PCIA-eligible resources is shown in Table 6. 12 Table 6: Monthly Excess Resources Used for System Reliability Procurement 13 14 As required, PG&E credited PABA and charged NSGBA for the value of the RA 15 transferred to CAM in June through September. However, in response to discovery, PG&E 16 disclosed that the value of excess resources utilized for October 2024 was not credited to 42 D.21-03-056, Decision Directing Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company to Take Actions to Prepare for Potential Extreme Weather in the Summers of 2021 and 2022, R.20-11-003 (Mar. 25, 2021). 43 PG&E Prepared Testimony, at 12-15, lines 3-20.
44 D.21-12-005, Phase 2 Decision Directing Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company to Take Actions to Prepare for Potential Extreme Weather in the Summers of 2022 and 2023, R.20-11-003 (Dec. 2, 2021). 45 D.21-02-015, Decision Directing to Take Actions for Potential Extreme Weather 2021 and 2022, R.20-11-003 (Mar. 26, 2021), at 183 (emphasis added).
46 PG&E response to CalCCA data request 1.08.
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22 the PABA and acknowledged that a correcting entry should be made.47 1 The of 2 excess RA associated with October 2024 has a value of that must be credited 3 to the PABA and charged to NSGBA. PG&E later confirmed in discovery that the 4 value was credited to PABA and charged to NSGBA in April 2025, plus associated prior period interest.48 5 The Commission should approve this correction to PG&E’s record 6 year accounting entries.
7 8 This concludes my testimony.
47 PG&E response to CalCCA data request 1.10.
48 PG&E response to CalCCA data request 3.01.

ATTACHMENT A
Curriculum Vitae of Brian Dickman

BRIAN DICKMAN
Partner
Economics | Strategy | Stakeholders | Sustainability
www.newgenstrategies.net

CONTACT
225 Union Boulevard, Suite 450
Lakewood, CO 80228
[email protected]
www.newgenstrategies.net

EDUCATION
Master of Business Administration,
Finance Emphasis, University of Utah
Bachelor of Science, Accounting, Utah
State University

KEY EXPERTISE
Cost of Service and Rates
Financial Analysis and Modeling
Power Charge Indifference Amount
Regulatory Strategy
Revenue Requirement
Mr. Brian Dickman is a partner in NewGen’s energy practice with over 20 years of utility industry experience. Mr. Dickman’s career includes over a decade working for PacifiCorp, a vertically integrated investor-owned utility, including senior-level positions in regulatory, financial, and commercial roles. He began consulting in 2017, assisting a wide array of clients across the United States and internationally, including utilities, large consumers, and private investment firms. Mr. Dickman has extensive experience preparing and evaluating utility revenue requirements and cost allocation studies, developing utility-avoided costs, and analyzing the impact of new initiatives and transactions on a utility and its customers. In addition to his extensive technical experience, Mr. Dickman understands the regulatory governance process, and he has personally testified as an expert witness before state public utility commissions in California, Idaho, Indiana, Oregon, Utah, Washington, and Wyoming.

Mr. Dickman advises numerous Community Choice Aggregator (CCA) clients in California, focusing on regulatory and rate issues such as the state-mandated exit fee known as the Power Charge Indifference Adjustment (PCIA). He also represents California CCAs as a member of the Cost Allocation Mechanism Procurement Review Groups for PG&E and Southern California Edison, which the California Public Utility Commission established to provide an independent review of the centralized procurement of local generation capacity requirements.

RELEVANT EXPERIENCE
Electric Cost of Service, Rate Design, and Regulatory
Analysis
Mr. Dickman leads projects developing utility revenue requirements, preparing cost of service and rate design studies, and performing financial and regulatory analyses for electric utilities. Mr. Dickman previously held leadership positions at a multi-billion-dollar utility. He interfaced with state regulatory agencies in support of revenue requirements, cost recovery mechanisms, avoided costs, valuations of potential asset acquisitions and other commercial opportunities, and financial impacts of utility initiatives. Mr. Dickman now works with clients and stakeholders to prepare pro forma financial models to determine revenue sufficiency, evaluate the cost of service studies and rate design proposals, and support such proposals before local and state governing bodies. Mr. Dickman’s experience also includes evaluating the financial and rate impact of proposed mergers and acquisitions, acquisition and divestiture of utility assets, negotiated retail service contracts, changing business models, and stranded costs due to exiting load. A sample of Mr. Dickman’s utility clients includes the following:
 Abu Dhabi Distribution
Company, UAE
 Central Coast Community
Energy, CA
 City and County of San
Francisco, CA
 Clean Power Alliance, CA
 Duke Energy, NC
 East Bay Community Energy, CA
 Hydro One, Ontario, Canada
 Liberty Utilities, CA

BRIAN DICKMAN
Partner
Thoughtful Decision Making for Uncertain Times 2
Electric Cost of Service, Rate Design, and Regulatory Analysis (cont.)  Lubbock Power and Light, TX
 Minnesota Power, MN
 New York Power Authority, NY
 Portland General Electric, OR
 San Diego Community
Power, CA
 San Jose Clean Energy, CA
 Silicon Valley Clean Energy
Authority, CA
 Vermont Gas Systems, VT
Non-Utility Clients
A sample of Mr. Dickman’s non-utility clients includes the following:
 Blackstone Group, NY
 California Community Choice
Association, CA
 Facebook, CA
 Hemlock Semiconductor, MI
 Newmont Mining, NV
 SABIC Innovative Plastics, IN
 Tri-County Metropolitan
Transportation District, OR
 Vistra Energy, TX
Expert Witness and Litigation Support
Mr. Dickman provides comprehensive expert witness testimony related to utility revenue requirements, cost of service, rate design, and other ratemaking issues before state and local regulatory bodies. He has provided litigation support in wholesale and retail jurisdictions, including California, Idaho, Indiana, Oregon, Washington, Wyoming, Utah, the Federal Energy Regulatory Commission, and Ontario Energy Board. Mr. Dickman offers expert witness testimony and litigation support in the following areas.

Revenue Requirement | Cost Allocation | Rate Design
Mr. Dickman prepared revenue requirements, inter-jurisdictional cost allocation, coincident peak allocation studies, and supporting testimony for PacifiCorp over many years. He now provides litigation support and expert testimony for clients wishing to review utility filings on revenue requirements, cost allocation, and rate design, including program-specific rate tariffs.

Power Supply Costs | Stranded Costs | Rate Adjustment Mechanisms Mr. Dickman has prepared and evaluated variable power supply cost forecasts, power supply cost balancing accounts and other rate mechanisms, stranded costs, and exit fees for departing loads. Since 2019, Mr. Dickman has actively participated in PCIA matters in California on behalf of CCA clients.

Avoided Costs | Resource Valuation
Mr. Dickman provided expert testimony for PacifiCorp on various components included in a proposed method for valuing solar generation resources, the calculation of Public Utility Regulatory Policies Act avoided costs for large resources and support of modifications to the avoided cost calculation for small resources.

BRIAN DICKMAN
Partner
NewGen Strategies and Solutions, LLC 3

WORKSHOPS AND PRESENTATIONS
Host organizations and the topics Mr. Dickman presented are displayed below.

Advanced Workshop in Regulation and Competition, Center for Research in Regulated Industries, 2018
Customer Choice at a Vertically Integrated Utility
Advanced Workshop in Regulation and Competition, Center for Research in Regulated Industries, 2018

Page 1 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

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

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

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

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

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

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

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

8. 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

Page 2 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

9. 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

10. 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

11. 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

12. 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

13. 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

14. 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

15. 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

Page 3 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

16. 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

17. 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

18. 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

19. 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

20. 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

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

Page 4 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

22. 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

23. 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

24. 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

25. 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

26. 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

27. 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

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

Page 5 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

29. 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

30. 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

31. 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

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

33. 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

34. 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

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

Page 6 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

36. 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

37. 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

38. 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

39. 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

40. 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

41. 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

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

Page 7 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

43. 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

44. 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

45. 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

46. 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

47. 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

48. 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

49. 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

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

Page 8 ends

Record of Testimony: Brian Dickman

UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR

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

52. 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

53. 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

54. 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

55. 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

56. 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
PG&E Responses to CalCCA Data Requests
ERRA-2024-PGE-Compliance_DR_CalCCA_MDR001-Q008 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
2024 Energy Resource Recovery Account – Compliance
Application 25-02-XXX
Data Response
PG&E Data Request No.: CalCCA_MDR001-Q008
PG&E File Name: ERRA-2024-PGE-Compliance_DR_CalCCA_MDR001-Q008 Request Date: December 31, 2024
Requester DR No.: MDR001
Requesting Party: California Community Choice Association Requester: Nikhil Vijaykar
Date Sent: February 28, 2025
PG&E Witness(es): Robert Gomez – Energy Policy and Procurement SUBJECT: PG&E SHALL INCLUDE THE FOLLOWING WITH EACH ERRA COMPLIANCE APPLICATION – FROM SETTLEMENT AGREEMENT
QUESTION 008
Resource adequacy information as follows:
(1) sold, unsold and retained resource adequacy by resource and balancing account (RA Tracker)
(2) system, local and flex positions for solicitations governed by Appendix S including the data as presented in the attached RA Position Table for (a) each solicitation in which RA for delivery in the record year was offered for sale (b) at the time each solicitation took place
(3) all Tier 1 advice letter filings addressing Operational Constraints, including confidential attachments.

ANSWER 008
The attachment to this data response contains confidential information protectable under Decision 14-10-033, Decision 06-06-066, and/or Public Utilities Code Section 454.5(g) – Subject to NDA
(1) See attachment: “ERRA-2024-PGE-Compliance_DR_CalCCA_MDR001- Q008Atch01CONF.xlsx”
(2) See attachment “ERRA-2024-PGE-Compliance_DR_CalCCA_MDR001- Q008Atch02CONF.xlsx”
(3) See attachments: “ERRA-2024-PGE-Compliance_DR_CalCCA_MDR001- Q008Atch03CONF.pdf” and “ERRA-2024-PGE-Compliance_DR_CalCCA_MDR001-Q008Atch04CONF.pdf” Attachment(s) Confidential
ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q006 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
2024 Energy Resource Recovery Account – Compliance
Application 25-02-013
Data Response
PG&E Data Request No.: CalCCA_001-Q006
PG&E File Name: ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q006 Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: California Community Choice Association Requester: Nikhil Vijaykar
Date Sent: April 25, 2025
PG&E Witness(es): Robert Gomez – Energy Policy and Procurement QUESTION 006
Referring to PG&E’s prepared testimony page 8-7, lines 2-6: Please explain what is meant by “while not required by the BPP, also offered all volumes of available RA to the market.” Please explain in detail the manner in which “all volumes of available RA” were “offered” to the market, as well as the volume and timing of those offers.

ANSWER 006
As stated in PG&E’s prepared testimony page 8-6, lines 25-28, “The BPP does not obligate PG&E to offer any volumes of RA determined to be available pursuant to the formulas set forth in Appendix S, except through the CAISO capacity procurement mechanism competitive solicitation process.” However, PG&E does endeavor to sell all the volumes as determined by the formulas.

Volumes of available RA were primarily offered into the market through numerous solicitations at various times as well as via broker and bilateral transactions. For volume and timing, please refer to the responses for “ERRA-2024- Compliance_DR_CalCCA_001-Q004,” ERRA-2024-Compliance_DR_CalCCA_001- Q005,” “ERRA-2024-Compliance_DR_CalCCA_001-Q007” and “ERRA-2024- PGECompliance_DR_CalCCA_MDR001-Q008Atch02CONF.xlsx.”
ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q008 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
2024 Energy Resource Recovery Account – Compliance
Application 25-02-013
Data Response
PG&E Data Request No.: CalCCA_001-Q008
PG&E File Name: ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q008 Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: California Community Choice Association Requester: Nikhil Vijaykar
Date Sent: April 25, 2025
PG&E Witness(es): Robert Gomez – Energy Policy and Procurement QUESTION 008
Referring to PG&E’s prepared testimony page 8-4 line 31 through page 8-5 line 8:

Please provide workpapers with details demonstrating how PG&E met its summer reliability procurement targets in 2024. Details should include specific resources and quantities used to meet the targets by month.

ANSWER 008

THE ATTACHMENT TO THIS DATA RESPONSE CONTAINS CONFIDENTIAL INFORMATION PROTECTABLE UNDER DECISION 14-10-033, DECISION 06-06- 066, AND/OR PUBLIC UTILITIES CODE SECTION 454.5(g) – SUBJECT TO NDA.

PG&E objects to this request on the ground that it seeks information that is not relevant to the subject matter of this proceeding and not reasonably calculated to lead to the discovery of admissible evidence as “how” PG&E met is summer reliability procurement targets is outside the scope of this proceeding. Subject to the foregoing, please refer to “ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q008Atch01CONF.xlsx.” Attachment(s) Confidential

Attachment(s) Confidential

ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q018 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
2024 Energy Resource Recovery Account – Compliance
Application 25-02-013
Data Response
PG&E Data Request No.: CalCCA_001-Q018
PG&E File Name: ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q018 Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: California Community Choice Association Requester: Nikhil Vijaykar
Date Sent: April 25, 2025
PG&E Witness(es): Robert Gomez – Energy Policy and Procurement QUESTION 018
Referring to PG&E’s response to Joint CCA MDR 1.08: Please demonstrate how the 2024 Operational Constraints are included in PG&E’s 2024 RA Tracker (i.e., are Operational Constraints included in Retained, Sold, or Unsold RA?).

ANSWER 018
The 2024 Operational Constraints are included in PG&E’s 2024 RA Tracker in the “Derate” column and are recorded as Retained RA.

ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q019 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
2024 Energy Resource Recovery Account – Compliance
Application 25-02-013
Data Response
PG&E Data Request No.: CalCCA_001-Q019
PG&E File Name: ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q019 Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: California Community Choice Association Requester: Nikhil Vijaykar
Date Sent: April 25, 2025
PG&E Witness(es): Robert Gomez – Energy Policy and Procurement QUESTION 019
Referring to PG&E’s response to Joint CCA MDR 1.08: Please demonstrate how the 2024 Portfolio Reserves are included in PG&E’s 2024 RA Tracker (i.e., are Portfolio Reserves included in Retained, Sold, or Unsold RA?).

ANSWER 019
The 2024 Portfolio Reserves are included in PG&E’s 2024 RA Tracker in the PG&E Compliance volumes, and are classified as Retained RA.

ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q029 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
2024 Energy Resource Recovery Account – Compliance
Application 25-02-013
Data Response
PG&E Data Request No.: CalCCA_001-Q029
PG&E File Name: ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q029 Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: California Community Choice Association Requester: Nikhil Vijaykar
Date Sent: April 25, 2025
PG&E Witness(es): Christopher Pezzola – Finance
QUESTION 029
Referring to PG&E’s prepared testimony page 12-27, lines 5-11: Please provide a complete copy of the referenced Internal Audit report and conclusions.

ANSWER 029
See attached “ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q029Atch01.” ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q029Atch01
ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q029Atch01
ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q029Atch01
ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q029Atch01
ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q030Supp01 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
2024 Energy Resource Recovery Account – Compliance
Application 25-02-013
Data Response
PG&E Data Request No.: CalCCA_001-Q030Supp01
PG&E File Name: ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q030Supp01 Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: California Community Choice Association Requester: Nikhil Vijaykar
Date Sent: May 2, 2025
(Original)
July 30, 2025
(Supplemental)
PG&E Witness(es): Cecilia Guiman/Christopher Pezzola – Customer and Enterprise Solutions/Finance
QUESTION 030
Referring to PG&E’s prepared testimony page 12-27, lines 12-13: Please provide a complete copy of PG&E’s Management Action Plan to implement the referenced Internal Audit recommendations.

ANSWER 030
Please see attachment “ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q030Atch01” for a copy of the original management action plan provided to mitigate the issue.

While some actions have been completed, additional actions are required to fully confirm whether there exists a programming logic issue related to tracking the vintages of customers moving within the same CCA, and if the issue is confirmed, then to address it. As a result, an extension to the action plan is being finalized that will include the following corrective actions:
• Determination of whether there is a programming logic issue, • Determination of the extent of the condition if there is a logic issue (i.e., the number of customers moving within a CCA that have been incorrectly vintaged, if any, due to the programming logic ),
• Identification of actions to update the programming logic (if any), and • Finalization of next steps.

Management is currently working to identify the specific resources that will perform these actions and estimating the date for completion of each action. Management anticipates having these details finalized by July 31, 2025, and will provide an updated action plan at that time.

ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q030Supp01 Page 2 ANSWER 030 SUPPLEMENTAL 01
PG&E’s updated action plan as of July 31, 2025, to implement Internal Audit’s recommendations, is summarized below.
• The determination of whether there is a programming logic issue has been completed, and it was determined there was an issue. See PG&E’s response to “ERRA-2024-PGE-Compliance_DR_CalCCA_003-Q009” dated July 16, 2025 for details of the programming logic issue.
• The determination of the extent of the condition (i.e., the number of customers moving within a CCA that have been incorrectly vintaged, if any, due to the programming logic), is in progress.
o Business Requirements Design Documents to develop the query to determine the extent of the condition are complete. The query is currently under development and expected to be completed by the end of Q3 2025.

Analysis of query results are expected to be completed by the end of Q4 2025.
• Identification of actions to update the programming logic (if any), is in progress.

Business Requirements Design Documents for programming logic updates have been completed. Cost and schedule estimation of the programming logic updates is underway, and is expected to be completed by the end of Q4 2025. • Finalization of next steps is dependent upon a determination of the extent of the condition as well as the cost and schedule estimate for programming logic updates. PG&E expects to finalize next steps by the end of Q4 2025.

ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q030Atch01
ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q031 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
2024 Energy Resource Recovery Account – Compliance
Application 25-02-013
Data Response
PG&E Data Request No.: CalCCA_001-Q031
PG&E File Name: ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q031 Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: California Community Choice Association Requester: Nikhil Vijaykar
Date Sent: May 2, 2025
PG&E Witness(es): David Gutierrez – Customer and Enterprise Solutions QUESTION 031
Referring to PG&E’s prepared testimony page 12-27, lines 17-18: Please provide PG&E’s written policy detailing the ‘acceptable documentation’ for customer vintaging classifications completed in response to the Internal Audit corrective action.

ANSWER 031
Since CCAs began serving customers in PG&E’s territory, PG&E has worked with CCAs and their back-office billing providers to enroll geographic areas into CCA service.

The dates in which PG&E enrolls geographic areas in CCA service establishes the vintage year for the respective geographic location. The CCA also informs PG&E of the month in which to enroll the customers and sends a full list of customers for PG&E to enroll in CCA service. PG&E attempted to save the dates and customer lists that are provided to them by the CCA for enrollment, but has potentially missed this on occasion. PG&E also provides lists for the CCA during the enrollment containing each new customer and the enrollment date that coincides with the vintage year.

Since the internal audit described in PG&E’s testimony was completed, PG&E’s Community Vitality team is also saving emails from CCAs, and their back office providers in a SharePoint site. In this site we are also keeping the customer lists sent to PG&E by the back-office biller. In addition, an excel database is maintained with all CCA expansions to new territories containing the dates of the expansion and the vintage year that corresponds to that expansion date.

ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q032 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
2024 Energy Resource Recovery Account – Compliance
Application 25-02-013
Data Response
PG&E Data Request No.: CalCCA_001-Q032
PG&E File Name: ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q032 Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: California Community Choice Association Requester: Nikhil Vijaykar
Date Sent: May 2, 2025
PG&E Witness(es): Cecilia Guiman – Customer and Enterprise Solutions QUESTION 032
Referring to PG&E’s prepared testimony page 12-28, lines 1-5: Please explain what responsibilities now belong to the Revenue Controls & Policy team because it has been assigned ownership over the customer vintaging programming logic.

ANSWER 032
The Revenue Controls & Policy team has now assumed ownership of the PCIA vintage and will work with Information Technology to ensure the programming logic aligns with the requirements of Decision 16-09-044. Please see PG&E’s response, “ERRA-2024- PGE-Compliance_DR_CalCCA_001-Q030,” and “ERRA-2024-PGE-Compliance_DR_CalCCA_001-Q030Atch01” regarding the remaining action plan.

ERRA-2024-PGE-Compliance_DR_CalCCA_003-Q001 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
2024 Energy Resource Recovery Account – Compliance
Application 25-02-013
Data Response
PG&E Data Request No.: CalCCA_003-Q001
PG&E File Name: ERRA-2024-PGE-Compliance_DR_CalCCA_003-Q001 Request Date: July 1, 2025
Requester DR No.: 003
Requesting Party: California Community Choice Association Requester: Nikhil Vijaykar
Date Sent: July 16, 2025
PG&E Witness(es): Ryan Stanley – Finance
QUESTION 001
Referring to PG&E’s response to CalCCA data request 1.10: Did PG&E record the correcting entry to credit PABA for excess resources utilized for October 2024 business? If yes, please provide workpapers quantifying the final amount of the correcting entry, including principal and interest. If no, please explain when PG&E will make the entry.

ANSWER 001
The attachment to this data response contains confidential information protectable under Decision 14-10-033, Decision 06-06-066, and/or Public Utilities Code Section 454.5(g)
PG&E had recorded the correcting entry in April 2025. Refer to the attached document:
“ERRA-2024-PGE-Compliance_DR_CalCCA_003-Q001Atch01CONF”

ERRA-2024-PGE-Compliance_DR_CalCCA_003-Q006 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
2024 Energy Resource Recovery Account – Compliance
Application 25-02-013
Data Response
PG&E Data Request No.: CalCCA_003-Q006
PG&E File Name: ERRA-2024-PGE-Compliance_DR_CalCCA_003-Q006 Request Date: July 1, 2025
Requester DR No.: 003
Requesting Party: California Community Choice Association Requester: Nikhil Vijaykar
Date Sent: July 16, 2025
PG&E Witness(es): Christopher Pezzola – Finance
QUESTION 006
Referring to PG&E’s response to CalCCA data request 1.29 and Attachment 1: PG&E concluded that 97% of the sampled customers appeared to be accurately assigned to their respective vintages. Does that mean that the other 3% were incorrectly assigned? If not, please explain.

ANSWER 006
The PG&E Internal Auditing comment does not mean that 3% of the sampled customers were incorrectly assigned. This comment means that there was not enough available documentation to definitively support the accuracy of the vintaging for 3% of the sample.

ERRA-2024-PGE-Compliance_DR_CalCCA_003-Q007 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
2024 Energy Resource Recovery Account – Compliance
Application 25-02-013
Data Response
PG&E Data Request No.: CalCCA_003-Q007
PG&E File Name: ERRA-2024-PGE-Compliance_DR_CalCCA_003-Q007 Request Date: July 1, 2025
Requester DR No.: 003
Requesting Party: California Community Choice Association Requester: Nikhil Vijaykar
Date Sent: July 16, 2025
PG&E Witness(es): Christopher Pezzola – Finance
QUESTION 007
Referring to PG&E’s response to CalCCA data request 1.29 and Attachment 1: Please explain the process PG&E implemented, or will implement, to correct the vintage assignment for customers found to be assigned incorrectly.

ANSWER 007
As stated in the answer to “ERRA-2024-PGE-Compliance_DR_CalCCA_003-Q006,” PG&E did not state that customers were incorrectly vintaged. The comment notes that PG&E did not formally define accountability for maintaining support for customer vintaging assignments, and consequently, could not produce sufficient records to support all of its vintaging classifications.

To address this issue, PG&E assigned accountability to Customer Vitality (effective, 8/15/2024) to maintain documentation supporting phase-in vintages. Customer Vitality has designated a web-based repository to store supporting documentation.

ERRA-2024-PGE-Compliance_DR_CalCCA_003-Q009 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
2024 Energy Resource Recovery Account – Compliance
Application 25-02-013
Data Response
PG&E Data Request No.: CalCCA_003-Q009
PG&E File Name: ERRA-2024-PGE-Compliance_DR_CalCCA_003-Q009 Request Date: July 1, 2025
Requester DR No.: 003
Requesting Party: California Community Choice Association Requester: Nikhil Vijaykar
Date Sent: July 16, 2025
PG&E Witness(es): Cecilia Guiman – Customer and Enterprise Solutions QUESTION 009
Referring to PG&E’s response to CalCCA data request 1.33: Please confirm PG&E’s response means that, currently, PG&E’s system assigns a customer its vintage according to its default (phase in) vintage, and if that customer moves to a CCA territory that is assigned a different vintage, the customer currently retains its original vintage rather than adopt the vintage of the new location. If not confirmed please explain further.

ANSWER 009
The Business Requirements Design Documents indicate that CC&B vintaging logic assigns a customer its vintaging according to its default (phase in) vintage, and that if that customer moves to a CCA territory that is assigned a different vintage, the customer is assigned the default (phase in) vintage of the new CCA territory. This logic is consistent with Decision 16-09-044 page 15: “If a CCA customer with one vintage moves to a CCA territory with a different vintage, that customer would adopt the vintage of his new location.”
The Business Requirements Design Documents indicate that CC&B vintaging logic tracks customers that affirmatively opt out of CCA service and then opt back in at a later time by setting their PCIA vintage to the date they depart from bundled service and start receiving CCA service. This logic is consistent with Decision 16-09-044 page 15:
“Rather than identifying how vintages should be assigned to the permutations of customer movement, we direct IOUs to track only customers that affirmatively opt out of CCA service and then opt back in at a later time. For those customers, their PCIA vintage should be set on the date they depart from bundled service and start receiving CCA service.”
The Business Requirements Design Documents indicate that CC&B vintaging logic resets a customer’s vintage to the default (phase in) vintage of the CCA territory each time a CCA customer moves to a new address. Customers who affirmatively opt out of CCA service, opt back in at a later time, and subsequently move to a new address within the incumbent CCA territory therefore have their vintage reset to the default ERRA-2024-PGE-Compliance_DR_CalCCA_003-Q009 Page 2
(phase in) vintage, rather than retaining their vintage. PG&E interprets the following language in Decision 16-09-044 to apply to the specific aforementioned scenario involving a customer move to a new address within the incumbent CCA territory:

Conclusion of Law Item 5 on page 24: “Resetting a CCA customer’s vintage each time that customer moves is inconsistent with Commission precedents,” and page 18:
“PG&E will need to adjust PCIA vintages for CCA customers who have been reset due to a change in address.” Revenue Controls and Policy is assessing the extent of this condition, and the feasibility of making changes to CC&B to accommodate this scenario.

Docket No.: A.24-11-007
Exhibit No.: CalCCA-01-E
Date: Revised September 18, 2025
Witness: Lori Mitchell, San Jose Clean Energy
Kris Van Vactor, Silicon Valley Clean Energy

TESTIMONY OF

THE CALIFORNIA COMMUNITY CHOICE ASSOCIATION

APPLICATION OF PACIFIC GAS AND ELECTRIC COMPANY FOR APPROVAL OF ELECTRIC RULE 30 FOR TRANSMISSION-LEVEL RETAIL ELECTRIC SERVICE A.24-11-007
i

TABLE OF CONTENTS
I. INTRODUCTION AND SUMMARY .................................................................................... 1 II. CCAS SERVE AS THE DEFAULT PROVIDERS FOR GENERATION SERVICE

FOR ALL CUSTOMERS IN THEIR SERVICE AREAS INCLUDING LARGE LOAD CUSTOMERS ........................................................................................................... 6 III. CCAS AS DEFAULT PROVIDERS OF GENERATION SERVICES NEED EARLY ACCESS TO LARGE LOAD CUSTOMER INFORMATION ............................. 9 A. PG&E Has Not Timely Shared New Large Load Information .........................................9 B. Access to Timely, Customer-Specific Data Enables Proactive Procurement Strategies .........................................................................................................................11 C. Insufficient Information-Sharing Disadvantages CCAs and Harms CCA Customers .......................................................................................................................14 IV. THE COMMISSION SHOULD ADOPT A FRAMEWORK FOR TIMELY
INFORMATION-SHARING BY PG&E FOR NEW LARGE LOADS ............................. 17 A. The Commission Should Adopt a Framework for Information-Sharing Between PG&E and the CCA with Clear Notice to the Potential Customer .................................17 B. Proposed Rule 30 Requires Clarification of the Respective Roles of the CCA and PG&E, Information to be Provided to Customers Regarding Customer Choice, and Information to be Provided to CCAs as Default Providers ........................18

APPENDIX
Appendix A: Redlines to PG&E’s Proposed Electric Rule 30

ATTACHMENTS
Attachment A: Curriculum Vitae of Lori Mitchell
Attachment B: Curriculum Vitae of Kris Van Vactor
Attachment C: Select Discovery Responses
1 1 I. INTRODUCTION AND SUMMARY
The California Community Choice Association (CalCCA) 1 2 presents this 3 testimony in the Application of Pacific Gas and Electric Company for Approval of Electric Rule No. 30 for Transmission-Level Retail Electric Service. 2 4 Sections I, II, and
5 IV of this testimony were prepared by or at the direction of Lori Mitchell, Director of San 6 Jose Clean Energy (SJCE). Ms. Mitchell’s qualifications are set forth in Attachment A. 7 Section III was prepared by or at the direction of Kris Van Vactor, Director of Power 8 Resources, Silicon Valley Clean Energy (SVCE). Mr. Van Vactor’s qualifications are set 9 forth in Attachment B.
10 In its Application, Pacific Gas and Electric Company (PG&E) proposes a new 11 Rule 30 Tariff to address interconnection of new customers requesting retail electric 12 service at transmission level voltages between 50 kilovolts (kV) and 230 kV (Large Loads).3 13 The Scoping Ruling in this proceeding includes as Issue 4.b: “What 14 information-sharing requirements should PG&E adopt to ensure that the [Community 1 CalCCA represents the interests of 24 community choice electricity providers in California: Apple Valley Choice Energy, Ava Community Energy (Ava), Central Coast Community Energy (3CE), Clean Energy Alliance, Clean Power Alliance of Southern California, CleanPowerSF, Desert Community Energy, Energy For Palmdale’s Independent Choice, Lancaster Energy, Marin Clean Energy (MCE), Orange County Power Authority, Peninsula Clean Energy (PCE), Pico Rivera Innovative Municipal Energy, Pioneer Community Energy, Pomona Choice Energy, Rancho Mirage Energy Authority, Redwood Coast Energy Authority (RCEA), San Diego Community Power, San Jacinto Power, San José Clean Energy (SJCE), Santa Barbara Clean Energy, Silicon Valley Clean Energy (SVCE), Sonoma Clean Power, and Valley Clean Energy. A subset of CalCCA members (Ava, 3CE, MCE, PCE, RCEA, SJCE and SVCE, collectively the Joint CCAs) addressed Pacific Gas and Electric Company’s (PG&E) application by, among other things, filing a response, dated December 23, 2024, and filing a reply to PG&E’s request for interim implementation, dated April 11, 2025. On June 18, 2025, the Assigned Administrative Law Judge (ALJ) to this proceeding approved the Motion for Party Status for CalCCA, which will represent all of its members in this proceeding, including the Joint CCAs.
2 Application of Pacific Gas and Electric Company (U 39 E) for Approval of Electric Rule No. 30 for Transmission-Level Retail Electric Service, Application (A.) 24-11-007 (Nov. 21, 2024) (Application).
3 Application, at 1.
2 1 Choice Aggregators (CCAs)] affected by Rule 30-related load growth can meet projected demand in their service areas?”4 2 Issue 4.b. is included because while PG&E provides 3 delivery service, CCAs are the default generation service providers in their service areas. 4 Therefore, in areas served by CCAs, PG&E will receive information when a customer 5 seeks to interconnect at the transmission level through a Rule 30 application. However, as 6 discussed further, CCAs do not currently receive information regarding a Large Load 7 customer seeking interconnection to PG&E’s system.
8 CalCCA generally supports PG&E’s efforts to attract new load by streamlining 9 and expediting interconnection of new customers to PG&E delivery system. Greater 10 clarity and coordination regarding new loads among all interests – PG&E, CCAs, and 11 new customers – will serve this goal. As acknowledged by Scoping Ruling Issue 4.b., the 12 coordination should extend to information-sharing between PG&E and the affected CCAs 13 during the interconnection process to enable timely procurement of generation supply to 14 the new load.
15 This testimony addresses CCAs’ role serving California customers (Section II) 16 and CCAs’ need for information regarding new load (Section III). It includes a proposal 17 for information-sharing from PG&E to the affected CCAs to ensure a customer’s chosen 18 generation supplier has sufficient notice to procure the supply cost-effectively and 19 equitably (Section IV). This testimony also identifies changes needed to PG&E’s 20 proposed Rule 30 Tariff to effectuate the proposed information-sharing requirements 21 (Section IV).
4 Assigned Commissioner’s Scoping Memo and Ruling, A.24-11-007 (Mar. 11, 2025) (Scoping Ruling), at 8.
3 1 PG&E states that it “has received 40 active applications for transmission level 2 service with demand of 4 MW or greater [and the] total combined current requested load of the 40 applications is 8,422 MW” in 2023-2024.5 3 PG&E represents that as of April, 4 2025, none of these applications have been withdrawn, and all are in the study/planning or design phases.6 5 In 2025, PG&E states that it has received four additional applications for transmission level service.7 6
7 PG&E is “seeing the growth of Data Centers in [its] service territory and 8 expect[s] this growth to continue with the large amounts of electrical demand needed to power such facilities.”8 9 As represented by PG&E, many of the data centers seeking interconnection in PG&E’s service territory are located in areas served by CCAs.9 10 11 Despite the role of CCAs as default providers for generation service in PG&E’s service 12 territory, CCAs often receive limited, if any, advance notice of new customer load, 13 including large load retail customers interconnecting at the transmission-level (referred to herein as Large Load).
10 14 Load expansion is included in the California Energy 5 PG&E Supplemental Testimony, A.24-11-007 (Mar. 21, 2025) (replacing PG&E’s originally filed Testimony, submitted Nov. 21, 2024) (PG&E Testimony), at 4, lines 4-7; see also Pacific Gas and Electric Company’s (U 39 E) Response to Administrative Law Judge’s Ruling Requesting Information on the Motion for Interim Implementation of Electric Rule No. 30 [Public Version], A.24-11-007 (Apr. 4, 2025) (PG&E Response to Interim Implementation Ruling), at 8. 6 PG&E Response to Interim Implementation Ruling, at 3, 8. 7 Id. at 9.
8 PG&E Testimony, at 5, lines 10-12.
9 See Pacific Gas and Electric Company’s (U 39 E) Response to the California Public Advocates Office’s Motion to Amend the General Rate Case Phase II Scoping Memo to Include Issues from Application 24-11-007, A.24-09-014, at 11 (“in California, retail choice means that PG&E may not be the Load Serving Entity that provides generation service to new very large load customers, even where PG&E is the utility providing delivery services from its transmission or distribution lines. A significant number of the very large load applications received thus far are for projects within areas served by [CCAs], and it is uncertain which customers may choose CCA service and which customers CCAs will elect to serve.”) (emphasis added). 10 CalCCA notes that large load customers may also interconnect at the distribution system level, resulting in similar information sharing needs for CCAs with respect to those customers. CalCCA 4 1 Commission’s (CEC) Integrated Energy Policy Report (IEPR) forecast communicated to 2 CCAs by PG&E. However, CCAs receive only an aggregate number, which does not 3 identify customers, their location, or timing of interconnection. The information provided 4 is insufficient for procurement planning. In addition, often the IEPR forecast for Large 5 Load differs significantly from the CCAs’ own forecasts. Attempts to reconcile the load 6 information, which ultimately impacts each CCA’s Resource Adequacy (RA) and/or 7 Integrated Resource Plan (IRP) requirements, have not been successful because CCAs 8 have no access to underlying customer information regarding forecasted Large Load. 9 Consequently, this lack of information prevents CCAs from proactively and cost-10 effectively procuring preferred energy products for Large Load customers. 11 Large Load customers interconnecting at the transmission-level often have a 12 choice of where to locate a new facility. If California seeks to attract and retain these 13 customers—and benefit from the downward pressure on delivery rates their participation 14 can provide—the state must adopt policies that enhance the optionality and support 15 available to Large Load customers. Key among these policies is ensuring coordination 16 between PG&E and CCAs, as the default generation service providers in their service 17 areas. This coordination will allow both the CCAs and PG&E to cost-effectively and 18 equitably serve new customers.
19 Consistent with California policy goals, this testimony recommends that the 20 Commission adopt information-sharing requirements obligating PG&E, as the delivery 21 service provider, to provide customer-specific information on new Large Loads to 22 affected CCAs within a reasonable timeframe. As an overarching principle for this acknowledges that this proceeding only relates to retail customers interconnecting at the transmission-level. 5 1 proceeding, when PG&E has the information, the default provider CCA should have 2 the information, consistent with confidentiality requirements, to enable the CCA to 3 work with customer and maximize the potential for efficient procurement; there is no 4 justification for delay.
5 This testimony recommends that the Commission adopt the following load 6 information-sharing requirements:
7 • For loads for which no application for interconnection service under Rule 8 30 (Interconnection Application) has been submitted to PG&E, but a load 9 inquiry has been made to PG&E and the utility is incorporating the 10 forecast into internal or external forecasts, PG&E should report to CCAs 11 on a quarterly basis the approximate location, size, and anticipated 12 timeline for integrating the new load. Information should be provided on 13 a per-project basis with a unique identifier that protects the customer's 14 identity if the customer does not wish to have their information shared 15 with the CCA.
16 17 • When an Interconnection Application has been submitted, PG&E should 18 provide each affected CCA a copy of the Interconnection Application 19 within 20 calendar days of submission to PG&E, with all information 20 relevant to potential CCA service including, as further described below in 21 Section III.B., customer name, location, facility type (e.g., data center, 22 commercial, retail, manufacturing), capacity ramp schedule, on-site 23 generation, and requested and current expected timing for the interconnection (Key Large Load Information).11 24 PG&E should also 25 provide all already submitted Applications for Interconnection, and any 26 additional Key Large Load Information, to an affected CCA within 20 27 calendar days of a Commission directive to do so.
28 29 • PG&E should provide each affected CCA with quarterly reports that 30 provide updates on the proposed interconnection timelines related to 31 Interconnection Applications, and any changes to Key Large Load 32 Information.
33 11 PG&E refers to the Interconnection Application as the “Application Phase,” namely, the milestone at which the customer first “submits a service energization request and study deposit.” See PG&E Answer 001 to Data Request Joint CCAs_003-Q001, Question 01 (Apr. 10, 2025) attached hereto in Attachment C. The Interconnection Application process is also described in PG&E’s proposed Rule 30 Tariff.
6 1 Appendix A to this testimony includes proposed changes to PG&E’s proposed Rule 30 Tariff to effectuate the proposed information-sharing framework. 12 2
3 The structure of this testimony is as follows:
4 • Section II addresses: (1) the role of CCAs as default providers of 5 generation service in their service areas; (2) current CCA service to data 6 center customers; and (3) a recommendation that the Commission adopt 7 information-sharing requirements to provide Key Large Load Information 8 promptly to an affected CCA.
9 10 • Section III addresses the importance of providing Key Large Load 11 Information as early as possible, including before an Interconnection 12 Application is submitted, to support affordable rates for California electric 13 customers, and concludes with a recommendation that the Commission 14 adopt information-sharing requirements that require information sharing at 15 the time PG&E learns of new load.
16 17 • Section IV outlines the proposed information-sharing framework and 18 associated Rule 30 Tariff revisions, included in a redline to PG&E’s 19 proposed Rule 30 Tariff, attached as Appendix A.
20 II. CCAS SERVE AS THE DEFAULT PROVIDERS FOR GENERATION SERVICE 21 FOR ALL CUSTOMERS IN THEIR SERVICE AREAS INCLUDING LARGE 22 LOAD CUSTOMERS
23 CCAs serve as the default providers of generation service for all customers 24 (residential and non-residential) in their service areas, subject to each customer’s ability 25 to opt out of CCA service. CCA customers continue to receive delivery service from the 26 investor-owned utility (IOU) serving that location. Consistent with the role as default 27 provider, CCAs currently provide 46 percent of electric generation service in PG&E’s service territory.13 28
12 On June 19, 2025, the Assigned ALJ granted CalCCA’s request to submit surrebuttal testimony on September 8, 2025, to provide an opportunity to respond to any proposal for information-sharing submitted by PG&E in its rebuttal testimony.
13 See, e.g., California Energy Demand 2023 Baseline LSE and BAA Tables, Form 1.1c (energy demand for 2023): https://efiling.energy.ca.gov/GetDocument.aspx?tn=255153; see also Decision (D.) 24-12-038, at 38 (“PG&E expects CCA and [Direct Access] providers to serve nearly two-thirds of total system sales in 2025.”).
7 1 New generation load in a CCA territory is automatically enrolled with, or defaulted to, the CCA serving that area.
14 2 PG&E’s Electric Rule 23.K.2 directs that
3 “[c]ustomers establishing electric service within a CCA service area shall be 4 automatically enrolled in CCA Service at the time their electric service becomes active 5 unless the customer submits a request to the CCA to opt-out and the CCA provides notification to PG&E of any such opt out request.”15 6 Rule 23.K.2 further directs that PG&E “promptly notify” the CCA of the new customer.16 7 8 A customer can opt out of CCA service in favor of IOU bundled service. However, 9 as outlined in Public Utilities Code section 366.2(c)(2) and stated in PG&E’s Electric Rule 10 23.G., if a customer is in a CCA service area and does not opt out of CCA service, the CCA will serve the customer.
17 11 As a result, the choice of being served by a CCA solely belongs 12 to the customer. Any new customer located in a CCA service area interconnected under the 13 new Rule 30 Tariff will be served by the CCA serving the location where the new facility is 14 located, unless that customer chooses to opt out of CCA service. 15 Consistent with the role embraced by CCAs as the default providers of generation 16 service, CCAs already serve Large Load customers interconnected at the transmission 17 level. While Large Load customers primarily take generation service on existing tariffs, CCAs have also worked directly with customers to design special agreements.18 18 For 14 Pub. Util. Code § 366.2(c)(2). 15 PG&E Electric Rule 23.K., Sheet 32 (emphasis added). 16 Ibid. 17 PG&E Electric Rule 23.G., Sheet 25 (“Pursuant to D.05-12-041, all customers, including active Direct Access customers, located within a CCA’s service area that have been offered service by the CCA that do not affirmatively decline such service (opt-out), shall be served by the CCA.”). 18 For example, SVCE entered into a special agreement with Google to provide 24/7 carbon-free energy service for Google’s offices in Mountain and Sunnyvale, California. SVCE agreed to match carbon-free electricity with Google’s local demand for at least 92 percent of all hours in the year – from a 8 1 example, SJCE currently serves five data centers and SVCE serves eight accounts 2 associated with at least four data centers.
3 Cost-effective and equitable generation service of Large Loads and all other 4 customers requires early and clear insight into the Large Load’s requirements. In its 5 Application, PG&E forecasts significant load growth in its territory. CCAs will likely provide generation service to many, if not most, of these customers.19 6 However, no 7 current standards exist for when PG&E will share Key Large Load Information with 8 CCAs. PG&E itself admits that it has not provided notice of the Interconnection Applications for load to the CCAs in its territory.20 9 More surprisingly, even in impacted 10 areas, such as the “cluster process for new transmission level retail electric customers 11 located in Alameda and Santa Clara Counties,” PG&E did not provide affected CCAs with notice.21 12
13 The Commission should adopt requirements for information sharing that ensure 14 both the CCA, for unbundled customers, and the IOU, for bundled customers, can secure 15 the most affordable rates for their customers. Absent such requirements, it is evident from tailored portfolio of renewable energy resources meeting additionality requirements. Google also agreed to flex its building electric loads to further improve carbon-free energy and cost performance, and to invest in electrification at its local facilities. The Google/SVCE agreement provides a scalable model for others to follow, and demonstrates the power of community collaboration in accelerating the transition to a clean energy future. See “Silicon Valley Clean Energy and Google Announce Comprehensive 24/7 Carbon-Free Energy Agreement” (June 15, 2022), located at https://svcleanenergy.org/news/silicon-valley-clean-energy-and-google-announce-comprehensive-24-7-carbon-free-energy-agreement/ 19 See PG&E Testimony, at 4, lines 4-7; see also note 9, supra (PG&E acknowledging that a “significant number” of Large Load applications received thus far are in CCA service areas). 20 See PG&E Answer to Data Request Joint CCAs_001-Q001, Question 01-a. (Jan. 29, 2025) (attached hereto in Attachment C) (“These applications do not concern the provision or procurement of electric commodity service. Thus, PG&E did not provide notice to energy providers such as Community Choice Aggregators (CCAs)….”).
21 See PG&E Answer to Data Request Joint CCAs_001-Q002, Question 02-a. (Jan. 29, 2025) (attached hereto in Attachment C) (“Given that the Pilot Cluster Process involved the interconnection of new electric customers, not the procurement of the electric commodity, PG&E did not provide notice directly to Community Choice Aggregators (CCAs).”).
9 1 PG&E’s past conduct (discussed further in Section III below) that PG&E will not share 2 Large Load information with CCAs. There should be no difference in the amount of time 3 PG&E, as the delivery service provider, has customer-specific information, and the 4 amount of time CCAs have the same customer-specific information. Any information 5 shared will be protected consistent with current oversight by the Commission of CCAs 6 and in accordance with currently effective Non-Disclosure Agreements (NDAs) between 7 the CCAs and PG&E.
8 CCAs are the default providers of generation service for new transmission-level 9 service customers in the CCA’s respective service area. Given this primary role serving 10 generation service, CCAs should receive information on new loads promptly, and 11 consistent with the framework described in Section IV of this testimony. 12 III. CCAS AS DEFAULT PROVIDERS OF GENERATION SERVICES NEED 13 EARLY ACCESS TO LARGE LOAD CUSTOMER INFORMATION
14 As noted above, cost-effective procurement decisions are driven by access to 15 customer information. As demonstrated by the load applications PG&E has received and not shared with the CCAs, including PG&E Advice Letter (AL) 7604-E22 16 (discussed below), the 17 CCAs are getting notice of new customers materially after PG&E is aware of the load. 18 These delays frustrate the ability of CCAs to make cost-effective procurement decisions 19 consistent with compliance requirements. Given the role of CCAs as default providers of 20 generation service, CCAs should have load information at the same time as PG&E. 21 A. PG&E Has Not Timely Shared New Large Load Information 22 22 PG&E Advice Letter (AL) 7604-E, Electric Rules 2, 15, and 16 Exceptional Case Submittal for Electric Transmission Interconnection for Sunnyvale Technology Partners LLC c/o Menlo Equities (May 27, 2025), at 2.
10 1 PG&E has not timely shared information regarding Interconnection Applications 2 for Large Loads. For example, on May 27, 2025, PG&E submitted AL 7604-E for 3 approval of an agreement between PG&E and Menlo Equities for a new 49 MW data 4 center in Sunnyvale, California. SVCE is the default generation provider for the proposed 5 location of the data center. According to AL 7604-E, Menlo Equities subm itted its application for service on April 11, 2024.23 6 Therefore, at that time PG&E obtained 7 information on the facility’s “peak demand,” “system load and generation forecasts” and “future energy resource needs.”24 8 At no point, however, did PG&E provide SVCE with 9 any notice of the prospective customer. SVCE only learned of the potential new load 10 when AL 7604-E was publicly submitted, 13 months after the application for service was 11 submitted to PG&E by the customer.
12 A similar advice letter for a data center in SJCE’s territory was submitted on April 18, 2025.25 13 In that instance, PG&E acknowledged that it did not share any information with the affected CCA in advance of the advice letter submittal. 26 14
15 PG&E stated in April, 2024 that it “anticipates there will be up to nine (9) 16 applications ready to submit to the Commission for review and approval by the end of June 30, 2025,” with additional filings “in the remainder of 2025 and 2026.”27 17 Only two 24 See PG&E Response to Interim Implementation Ruling), at 20-21 (describing PG&E’s use of customer information for determining Resource Adequacy and future energy needs, and PG&E’s provision of customer information to the California Independent System Operator and California Energy Commission).
25 See PG&E Advice Letter 7569-E, Electric Rule 2, 15, and 16 Exceptional Case Submittal for Electric Transmission Service Facilities for STACK (Apr. 18, 2025). 26 See Pacific Gas and Electric Company’s Reply to the Response to Joint CCAs to Advice 7569-E-Electric Rule 2, 15 and 16 Exceptional Case Submittal for Electric Transmission Service Facilities for STACK (May 15, 2025), at 2.
27 PG&E Response to Interim Implementation Ruling, at 8. 11 1 filings have been made as of the date of this Testimony (Stack and Menlo Equities), 2 leaving many still to be filed. To the extent that any of these facilities are in SVCE’s 3 service area, SVCE has received no notice of the new load from PG&E. 4 B. Access to Timely, Customer-Specific Data Enables Proactive Procurement 5 Strategies
6 7 Cost-effective procurement requires the CCA to consider the needs of each 8 individual customer as well as the broader compliance requirements for the CCA, 9 including RA, IRP, and the Renewables Portfolio Standard (RPS) requirements. The 10 further in advance the CCA can assess the needs of a particular customer and the timing 11 of its energization, the better able the CCA is to engage in a thoughtful and dynamic 12 procurement strategy.
13 A dynamic procurement strategy includes purchasing energy in long, medium, 14 and short-term markets to ensure that the CCA can cost-effectively meet the needs of its 15 customers without unnecessary reliance on any one market. However, a dynamic 16 procurement strategy is reliant on good data. Without timely information about potential 17 new load, and in particular Large Loads, and the timing of interconnection, the CCA 18 could under or over procure, increasing risk to its supply portfolio and customers. 19 As it stands now, CCA procurement strategies begin with the load forecast in the 20 IEPR as well as CCA internal load forecasting, which become more refined over time as 21 better information about individual customers becomes available. The challenge with this 22 approach is that “better information,” including information on Large Loads, has not been 23 made available to CCAs by PG&E until an advice letter is submitted, which is too late. 24 Going forward, to ensure that CCA procurement strategy results in the lowest possible 25 cost to ratepayers, it is necessary to ensure that Large Load information known by PG&E 12 1 as the delivery service provider is shared at the earliest possible point with CCAs. This 2 information can inform the IEPR load forecast, and it can be used to inform the load 3 forecast used for procurement over time.
4 The IEPR forecast materially impacts CCAs compliance requirements. 5 Substantial and sudden changes to CCA forecasts can increase RA requirements with 6 limited notice. IEPR forecasts have also historically been used to determine Load 7 Serving Entity (LSE) procurement requirements and, depending on the outcome of the 8 ongoing Reliable Clean Power Procurement Program (RCPPP), may continue to be used 9 for this purpose. In both cases, these compliance requirements endure regardless of 10 whether the load comes to fruition.
11 While RPS compliance is not directly impacted by the IEPR process, failure for 12 LSEs to accurately predict their own load could significantly impact the entity’s ability to remain compliant. This is especially true for compliance with Senate Bill (SB) 350,28 13 14 which requires LSEs to have sufficient long-term contracts, many of which are new build 15 and require several years to bring online. If an LSE learns, either through the IEPR or 16 through a new customer energizing, of significant new load too late (especially near the 17 end of a compliance period), it may materially impact their ability to comply. These load 18 forecast issues may also materially impact an IOU’s Energy Resource Recovery Account 19 (ERRA) forecast, and resulting Power Charge Indifference Adjustment charges. 20 A document recently presented by the CEC underscores these points. The IEPR 21 forecast for data centers includes projects that have: (1) active applications with 22 completed or to-be-completed engineering studies; (2) active applications prior to 28 SB 350 (DeLeón, Ch. 547, Statutes of 2015).
13 initiating engineering studies; and (3) project inquiries.29 1 The latter two categories 2 included in the forecast count for thirty-eight percent of the total projected capacity for PG&E.
30 3 PG&E, however, acknowledges that this load remains uncertain, assigning confidence intervals to the forecast load.
31 4 Including uncertain load is important for
5 planning. However, including such load can also lead to planning for load that never 6 arrives, leaving an LSE potentially on the hook for a long position. Without access to the 7 customer-specific information, the CCA is unable to assess for itself and its own 8 procurement portfolio how certain that load is and what changes to procurement strategy 9 may be required.
10 The IEPR forecast also fails to provide any detail on the new load and the 11 individual needs of the customer. For instance, a new customer may be intending to 12 purchase its own specific product (e.g., 24/7, carbon free), which would impact the 13 procurement choices made on behalf of the customer. Details on ramp schedule, load 14 type and interconnection schedule will also impact the type and timing of the 15 procurement and should be made known to CCAs at the time PG&E has the information. 16 There should be no material difference in the amount of time PG&E, as the delivery 17 service provider, has customer-specific information and the amount of time CCAs have 18 the same customer-specific information. The more notice available, the more competitive 19 the CCA (or PG&E, if the customer opts for bundled service) can be in its procurement. 20 This will result in cost savings for all customers.
29 See CEC, “Data Center Forecast” (Dec. 23 2024), at 3:
https://www.energy.ca.gov/sites/default/files/2024-12/Data_Center_Forecast_Update_ada.pdf. 30 Ibid. 31 Id. at 4. 14 1 Only receiving notice of Large Loads during the IEPR process is insufficient for 2 procurement decision-making. PG&E’s IEPR forecast does not provide information that 3 allows the CCA to: (1) independently determine the relative certainty of new Large Load; 4 and (2) modify load forecasts to reflect the evolving needs of the customer. 5 6 C. Insufficient Information-Sharing Disadvantages CCAs and Harms CCA 7 Customers
8 9 As the delivery service provider for customers in its territory, PG&E is often the 10 first stop for a new Large Load considering locating a facility in California. By 11 withholding the customer information required for load planning, PG&E impedes cost-12 effective procurement by the affected CCA. As described below, the lack of information 13 regarding planned Large Loads creates the following disadvantages for CCAs and CCA 14 customers: (1) lack of competitive parity between CCAs and PG&E; (2) inadequate 15 information to plan for reliability; (3) lack of notice to customers of their generation 16 service options; and (4) inability to capitalize on affordability benefits of cost-effective 17 procurement.
18 Competitive concerns: To maintain competitive parity between an affected CCA 19 and PG&E, there should be explicit rules ensuring the affected CCA has the same 20 information available to PG&E regarding Large Loads. Failure to do so allows PG&E 21 potentially to be able to use its exclusive role as delivery provider to preference PG&E’s 22 procurement department. As one example, at a recent technical conference at the Federal 23 Energy Regulatory Commission (FERC) on RA, Gillian Clegg, Vice President, Energy 24 Policy and Procurement at PG&E stated “I think what we’re saying publicly now is 12.8 25 gigawatts (GW) of applications have been submitted and about 1.4 GW of that is already 15 1 through final engineering and so we do think about 90 percent of what’s in final engineering will come to bear.”32 2 That the head of PG&E’s procurement department has 3 a defined confidence level in the PG&E forecast implies a degree of certainty in the load 4 which no CCA procurement team can have given their forecasters lack any information 5 to develop any assurance these loads will come online. The Commission should therefore 6 affirm in this proceeding that PG&E and affected CCAs obtain information on new Large 7 Load concurrently. Specifically, CCAs should receive such information within a 8 reasonable amount of time (20 calendar days) after PG&E’s delivery service team 9 receives information on new Large Load.
10 Reliability Concerns: Key Large Load Information is necessary for CCAs’ 11 resource planning purposes. Without this information, CCAs are unable to validate or 12 assure that a particular customer’s load is included in the IEPR load forecast. As a result, 13 unvalidated information could be used to set the RA or IRP requirements for the CCA. 14 This is problematic on a number of fronts, including affordability. However, as it relates 15 to reliability, unvalidated information can lead to a CCA planning for less resources to 16 satisfy RA requirements than necessary. To properly align planning with realistic load 17 forecasts, a CCA should have all relevant customer information necessary to afford the 18 opportunity to investigate on its own behalf the certainty of the load. The customer’s 19 chosen provider, CCA or PG&E, should be provided sufficient time to ensure reliability 20 requirements are met cost-effectively.
32 FERC Docket AD25-7-000, “Day 2: Commissioner-led Technical Conference Regarding the Challenge of Resource Adequacy in RTO and ISO Regions,” (June 5, 2025), at 5:33, video recording available at: https://ferc.gov/news-events/events/day-2-commissioner-led-technical-conference-regarding-challenge-resource (transcribed from video). 16 1 Customer Notice: Customers may not be aware that a CCA serves a location 2 targeted for development. PG&E should be transparent regarding the customer’s option 3 at the time of an Interconnection Application. Customers should be aware that the CCA 4 will be their generation service provider subject to the customer’s choice to opt out of 5 CCA service. Regardless of whether the customer is aware of the potential for CCA 6 service, the customer may not be aware of the need for the CCA to have early notice of 7 their new load. CCAs should have the opportunity to educate their presumptive 8 customers on the role of the CCA.
9 Affordability: As described throughout this section, ultimately all customers 10 benefit when the affected CCA and PG&E have sufficient notice of new loads, and 11 especially Large Loads. A longer runway for new procurement requirements enables the 12 affected CCA or PG&E, to cost-effectively procure for the new load. Without sufficient 13 notice, the generation provider will have to rely on the riskier short-term market, which 14 could result in higher prices for customers. In short, reasonable requirements for timely 15 information sharing empowers the affected CCA or PG&E to cost-effectively procure 16 generation for new Large Loads.
17 To promote cost-effective and equitable procurement, PG&E should be directed to 18 provide information on new Large Loads to the CCA promptly upon receipt of notice of or 19 an Interconnection Application. Legal requirements and customer relationships already 20 require that the CCA protect customer confidentiality. Any customer information provided 21 to CCAs by PG&E will be treated consistent with California law, rules established by the 22 Commission, and pursuant to the applicable NDA with PG&E. 17 1 IV. THE COMMISSION SHOULD ADOPT A FRAMEWORK FOR TIMELY 2 INFORMATION-SHARING BY PG&E FOR NEW LARGE LOADS
3 This testimony recommends that an information-sharing framework between 4 PG&E and any applicable CCA be adopted in connection with the Rule 30 Tariff. As set 5 forth below, this information-sharing framework will: (1) ensure a CCA serving the 6 location of a proposed new Large Load receives quarterly information regarding 7 customers seeking information regarding interconnection with PG&E’s transmission 8 system; (2) require PG&E to provide affected CCAs with Interconnection Applications, 9 including Key Large Load Information, within 20 calendar days of PG&E’s receipt (and 10 requires already submitted Interconnection Applications to be provided to the affected 11 CCAs); and (3) require PG&E to provide quarterly updates on the status of 12 Interconnection Applications and any changes to Key Large Load Information. In 13 addition, the Commission should require changes to the proposed Rule 30 tariff and form 14 Interconnection Application to effectuate such information sharing, as set forth in 15 redlines attached hereto as Appendix A.
16 A. The Commission Should Adopt a Framework for Information-Sharing Between 17 PG&E and the CCA with Clear Notice to the Potential Customer 18 19 As explained in Section II above, the CCA is the default generation service 20 provider to new customer load sited in the CCA service area. As demonstrated in Section 21 III, sufficient advance notice of new Large Load is required to ensure that the Large Load 22 can be served cost-effectively and equitably. Further, the affected CCA requires ongoing 23 information on any changes to the interconnection timeline and Key Large Load 24 Information for a new facility. Consistent with these facts, the Commission should adopt 25 the following framework for information- sharing between PG&E and the affected CCA:
18 1 • For loads for which no Application for interconnection service under Rule 2 30 (Interconnection Application) has been filed, but a load inquiry has 3 been made to PG&E and the utility is incorporating the forecast into 4 internal or external forecasts, PG&E should report to CCAs on a quarterly 5 basis the approximate location, size, and anticipated timeline for 6 integrating the new load. Information should be provided on a per-project 7 basis with a unique identifier that protects the customer's identity if the 8 customer does not wish to have their information shared with the CCA. 9 10 • When an Interconnection Application has been submitted, PG&E should 11 provide each affected CCA a copy of the Interconnection Application 12 within 20 calendar days of submission to PG&E, with Key Large Load 13 Information. PG&E should also provide all already submitted 14 Applications for Interconnection, and any additional Key Large Load 15 Information, to an affected CCA within 20 calendar days of a 16 Commission directive to do so.
17 18 • PG&E should provide each affected CCA with quarterly reports that 19 provide updates on the proposed interconnection timelines related to 20 Interconnection Applications, and any changes to Key Large Load 21 Information.
22 23 PG&E has stated in discovery that it is “willing to work with the Joint CCAs on the 24 appropriate information to be provided by PG&E to potential transmission level customers during the Electric Rule 30 application process.”33 25 The above-described 26 requirements provide a reasonable framework for PG&E to provide necessary and timely 27 customer information to affected CCAs.
28 B. Proposed Rule 30 Requires Clarification of the Respective Roles of the CCA and 29 PG&E, Information to be Provided to Customers Regarding Customer Choice, 30 and Information to be Provided to CCAs as Default Providers 31 32 Consistent with the proposed information-sharing requirement described above, 33 the approved Rule 30 tariff and any form Interconnection Application associated with 34 Rule 30 should also notify customers that if the proposed load is sited in a CCA’s service 33 See PG&E Answer to Data Request Joint CCAs_001-Q007, Question 07 (Jan. 29, 2025) (attached hereto in Attachment C).
19 1 area the affected CCA is the default provider of generation service. In addition, the 2 customer should be informed that, in light of this role and responsibility, the affected 3 CCA is entitled to and will receive information on the customer. The Commission 4 should direct PG&E to add the following language to Section 1. General of proposed 5 Rule 30, as reflected in the Rule 30 Tariff redline attached hereto as Appendix A:
6 8. For any Facility at a location within the service area of a Community 7 Choice Aggregator (CCA), the CCA is the default provider of generation 8 service. The affected CCA will automatically serve any new Applicant in 9 its service area subject to the choice of the Applicant to opt out of CCA 10 service to receive generation service from PG&E. Upon receipt of an 11 Application for a Facility in a CCA’s service area, PG&E will provide the 12 affected CCA a copy of the Application within 20 calendar days of 13 receipt, to ensure the CCA receives key information about the service 14 request to inform the CCA of the new customer, including the customer 15 name, location, facility type (e.g., data center, commercial, retail, 16 manufacturing), capacity ramp schedule, on-site generation, and requested 17 timing for the interconnection. PG&E will also provide to the affected 18 CCA within 20 calendar days any subsequent changes to the Application 19 and periodic updates to the interconnection timeline. Information provided 20 by PG&E to the CCA is subject to confidentiality protections established 21 by the Commission.
22 23 Additionally, ambiguity exists in the Rule 30 Tariff language regarding the 24 definition of “Retail Service.” The proposed Rule 30 Tariff definition of Retail Service is 25 the following:
26 “RETAIL SERVICE: Electric service to PG&E’s end-use or retail customers 27 which is of a permanent and established character and may be continuous, intermittent, or seasonal in nature.”34 28
29 Given the concerns of customer awareness discussed in Section III above, the proposed 30 Rule 30 Tariff should be updated to clarify the role of the CCA as the default generation 31 service provider and PG&E’s role as the default delivery service provider. PG&E stated 32 in discovery that it is amenable to making this change:
34 Proposed Rule 30 Tariff, at 17.
20 1 PG&E is willing to work with the Joint CCAs to clarify that the term 2 “Retail Service” does not include or relate to generation service. As an 3 initial proposal, PG&E suggests adding the following sentence to the 4 defined term “Retail Service”:
5 6 For purposes of this Rule, Retail Service does not include or relate to providing generation service and/or the electric commodity.35 7 8 9 PG&E’s proposed clarification should therefore be incorporated into Rule 30, as reflected 10 in CalCCA’s redline attached hereto as Appendix A.
11 The Commission should also direct PG&E to include in its proposed Rule 30 12 Interconnection Application language consistent with these redlines and the proposed 13 information-sharing requirements. In addition, the Interconnection Application should 14 provide a tool to assist the applicant to determine if the proposed facility will be in a 15 CCA’s service area. For any proposed facility in a CCA’s service area, PG&E should 16 provide information on how to contact the CCA and, as noted above, clear disclosures 17 that the information will be provided to the affected CCA as the facility’s default 18 provider of generation service.
19 California customers will benefit from new loads choosing to site new facilities in 20 the state. Clear policies and procedures, as well as the benefit of choice, are most likely to 21 encourage these facilities to site in California while protecting existing customers. The 22 changes described herein will also ensure competitive parity between PG&E and CCAs 23 in serving new Large Loads. Improved information sharing and cooperation will 24 maximize the ability of both the CCAs and PG&E to serve these new customers. 35 PG&E Response to Data Request Joint CCAs_001-Q006, Question 06. See PG&E Answer to Data Request Joint CCAs_001-Q006, Question 06 (Jan. 29, 2025) (attached hereto in Attachment C).

APPENDIX A
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TESTIMONY OF

THE CALIFORNIA COMMUNITY CHOICE ASSOCIATION

APPLICATION OF PACIFIC GAS AND ELECTRIC COMPANY FOR APPROVAL OF ELECTRIC RULE 30 FOR TRANSMISSION-LEVEL RETAIL ELECTRIC SERVICE REDLINES TO PG&E’S PROPOSED ELECTRIC RULE 30
A-1

APPENDIX A
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TESTIMONY OF THE CALIFORNIA COMMUNITY CHOICE ASSOCIATION

APPLICATION OF PACIFIC GAS AND ELECTRIC COMPANY FOR APPROVAL OF ELECTRIC RULE 30 FOR TRANSMISSION-LEVEL RETAIL ELECTRIC SERVICE A.24-11-007

PROPOSED REDLINES TO

PACIFIC GAS AND ELECTRIC COMPANY
PROPOSED ELECTRIC RULE NO. 30: RETAIL SERVICE

TRANSMISSION FACILITIES
Proposed text deletions show as bold and strikethrough
Proposed text additions show as bold and underlined
A. GENERAL

8. For any Facility at a location within the service area of a Community Choice Aggregator (CCA), the CCA is the default provider of generation service. The affected CCA will automatically serve any new Applicant in its service area subject to the choice of the Applicant to opt out of CCA service to receive generation service from PG&E. Upon receipt of an Application for a Facility in a CCA's service area, PG&E will provide the affected CCA a copy of the Application within 20 calendar days of receipt, to ensure the CCA receives key information about the service request to inform the CCA of the new customer, including the customer name, location, facility type (e.g., data center, commercial, retail, manufacturing), capacity ramp schedule, on-site generation, and requested timing for the interconnection. PG&E will also provide to the affected CCA within 20 calendar days any subsequent changes to the Application and periodic updates to the interconnection timeline. Information provided by PG&E to the CCA is subject to confidentiality protections established by the Commission.

G. DEFINITIONS FOR RULE 30
RETAIL SERVICE: Electric service to PG&E’s end use or retail customers which is of a permanent and established character and may be continuous, intermittent, or seasonal in nature.

For purposes of this Rule, Retail Service does not include or relate to providing generation service and/or the electric commodity.

ATTACHMENT A
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TESTIMONY OF

THE CALIFORNIA COMMUNITY CHOICE ASSOCIATION

APPLICATION OF PACIFIC GAS AND ELECTRIC COMPANY FOR APPROVAL OF ELECTRIC RULE 30 FOR TRANSMISSION-LEVEL RETAIL ELECTRIC SERVICE A.24-11-007

CURRICULUM VITAE OF LORI MITCHELL
LORI

MITCHELL
SKILLS
• Executive Leadership
• Clean Energy
• Utility Operations
• Technical Advising
• Local Government
• Problem Solving

BOARD POSITIONS
California Community Power,
President, previous Vice Chair
California Community Choice
Association, previous President
California Foundation on the
Environment and the Economy

EDUCATION
Cal Poly, Humboldt State
University:

BS: Engineering
Texas A&M: MBA

PROFESSIONAL SUMMARY
Executive professional with more than 25 years of
experience in utilities and renewable energy. Expert in clean energy, utility operations, and management.

Proven relationship builder with stakeholders, elected
officials, and staff. Recognized for track record of
success in building and leading high performing
organizations.

WORK HISTORY
CITY OF SAN JOSE, ENERGY - Director
San Jose, CA • 11/2017 - Current
• Successfully worked with the Mayor, City Council, and the City Manager’s office to start-up a new Department
providing electric generation service under the
community choice aggregation model.
• San Jose Clean Energy serves 350,000 customers and
has saved ratepayers more than $50 million dollars
while providing over 60% renewable energy.
• Successfully negotiated power supply agreements
totally over 1GW of new renewable projects valued at
over $4 billion dollars.
• Successfully managed an operating budget of over $500 million a year and ensured regulatory compliance with
the CPUC, CEC, CAISO as well as other agencies.
• Hired, trained, and onboarded over 60 staff
• Provided executive leadership to form a new municipal utility to support data centers including managing the
interconnection and electrical distribution design.

CITY OF SAN JOSE, ESD - Acting Director
San Jose, CA • 8/2024 – 3/17/25
• Provided executive leadership to oversee the
Environmental Services Department which includes
over 600 staff and operates retail water, regional
wastewater facility, recycling and garbage services,
stormwater, and other utility services.

CITY Of SAN FRANCISC0, SFPUC Multiple Positions,
ending in Director
San Francisco, CA • 2007 - 2017
• Provided executive leadership to synchronize efforts
across: Power Supply and Scheduling; Renewable
Generation; Energy Efficiency; Distribution and
Transmission Planning.
• Successfully managed a $500 million capital budget to ensure projects were completed within budget.

Projects included solar, energy efficiency, and initial designs for the Bay Corridor Transmission and
Distribution project located on the southeast side of
the city.
• Led negotiations for the energy contracts to support
the launch and growth San Francisco's CleanPowerSF
Community Choice Aggregation Program valued at $100
Million dollars.
• Managed SF’s Hetch Hetchy hydroelectric assets to
optimize power production within the constraints of
the water supply systems.
• Successfully represented the Department at public
meetings with the SF Board of Supervisors and the SF
Public Utilities Commission to obtain project approvals and discuss critical issues.
• Built high performing teams and successfully managed
a team of over 100 people to achieve the agencies
strategic business goals.
• Strategically led the team in constructing the largest municipal solar project located in an urban
environment.
• Led the power supply and scheduling group responsible for power trading and scheduling 385 MW of
hydroelectric generation into the CAISO market.
• Provided oversight for the implementation of the City's renewable energy program that consisted of solar PV,
wind, wave, and small hydro projects.
• Achieved $6M in savings by streamlining forecasting
procedures and implementing cost reduction strategies
for energy purchases and services as well as increasing coordination with the CAISO scheduling and
settlements groups.

POWERLIGHT / SUNPOWER CORPORATION - Senior
Engineer
Berkeley, CA • 1999 - 2007
• Oversaw the power modeling of various utility-scale
solar projects, including a 10MW project in Germany, a
15 MW project in Portugal, 20 MW in Spain, and several
smaller rooftop projects in the United States.
• Resolved performance and operational issues of
hundreds of solar projects to meet performance
specifications.
• Controlled engineering activities to maintain work
standards, adhere to timelines and meet quality
assurance targets.
• Produced and presented multiple technical papers in
various industry conferences.
• Educated clients on the energy production and
performance of their solar project.

NATIONAL RENEWABLE ENERGY LABORATORY
Washington, DC • 1998

CALIFORNIA ENERGY COMMISSION
Sacramento, CA • 1997

CALIFORNIA AIR RESOURCES BOARD
Sacramento, CA • 1996

LICENSE
California Professional Engineer (PE): Mechanical
AWARD:

Silicon Valley Business Journal: Women of Influence 2023

PUBLICATIONS
Authored multiple technical papers on the performance
of solar energy projects, published in IEEE journals
.

ATTACHMENT B
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TESTIMONY OF

THE CALIFORNIA COMMUNITY CHOICE ASSOCIATION

APPLICATION OF PACIFIC GAS AND ELECTRIC COMPANY FOR APPROVAL OF ELECTRIC RULE 30 FOR TRANSMISSION-LEVEL RETAIL ELECTRIC SERVICE A.24-11-007

CURRICULUM VITAE OF KRIS VAN VACTOR
1 S. Kris Van Vactor
5850 Balcom Ave., Encino, CA 91316
��503-544-5142 | ��[email protected]
Professional Profile
Results-oriented leader in procurement, policy, and energy market strategy with over 20 years of experience spanning utility operations, regulatory policy, wholesale energy markets, and economic consulting. Proven success in managing multidisciplinary teams, leading major market transitions, and negotiating complex energy contracts. Skilled in economic analysis, project implementation, and cross-functional collaboration in regulated and deregulated energy environments.

Core Competencies
Strategic Energy Procurement, Policy Analysis & Regulatory Affairs, Team Leadership & Development, Economic & Statistical Analysis, Program & Project Management, Technical Writing & Reporting, Contract Negotiation, Contract Management, Organizational Budgeting, Procurement Planning, Market Operations (CAISO, FERC), Resource Adequacy, Energy Hedging, Software: Microsoft Office, VBA, eViews
Professional Experience
Director of Power Resources
Silicon Valley Clean Energy (SVCE), Sunnyvale, CA
2024 – Present
• Lead an organization of procurement professionals that specialize in Front-office, Back-office and Planning activities
• Oversaw the management of a clean portfolio of generation assets with contracts totaling ~2 billion
• Provide strategic guidance for short-term and long-term procurement needs • Assess and manage group functions and needs as workflow dictates Wholesale Energy Markets Manager
Silicon Valley Clean Energy (SVCE), Sunnyvale, CA
2022 – 2024
• Lead procurement and operations for energy hedging and Resource Adequacy. • Oversaw transition to CAISO’s “Slice of Day” RA market structure • Represent SVCE in stakeholder forums (CalCCA and others) 2 • Led joint negotiations for a 100 MW New Mexico wind import (SunZia project). • Supported integration of long-term renewable contracts (e.g., Yellow Pine, Victory Pass).

Senior Project Manager/Senior Advisor, CAISO Settlements Southern California Edison (SCE), Rosemead, CA
2017 – 2022
• Spearhead policy, strategy and implementation of products for use in organized energy markets
• Uphold role as workgroup representative on simultaneous projects while assuring the completion of project-specific goals, milestones and timelines • Identify and implement various CAISO based initiatives including changes to Congestion Revenue Rights settlements, Market Settlement Timeline Transformation, Intertie Deviation Settlement and CAISO Summer Readiness changes
• Identified a policy gap where energy storage resources were being charged Resource Adequacy Availability Incentive Mechanism despite bidding their full capacity • Represented SCE Back office in internal and external market design and policy forums.

Project Manager
Southern California Edison (SCE), Rosemead, CA
2013 - 2017
• Identified changes and implemented them in order to support market changes initiated by CAISO including updated Capacity Procurement Mechanism and Reliability Services Initiative rules as well as Full Network Model Expansion.
• For each project identified software needs, tracked development and adjusted timelines accordingly
• Developed a strategic framework for bidding standalone batteries into CAISO marketplace • Onboarded 92 MW of aggregated distribution level solar resources into CAISOs market. •Represented SCE Front office in internal and external market design and policy forums.

Energy Operations Specialist
Southern California Edison (SCE), Rosemead, CA
2011 - 2013
• Developed a position report to track various market specific metrics for real-time traders • Provided project support on a variety of projects
3 • Onboarded renewable resources into Southern California Edison's generation portfolio Senior Financial Analyst
Southern California Edison (SCE), Rosemead, CA
2009 - 2011
• Developed and implemented strategies and software changes for Virtual Bidding • Provided project support on a variety of projects
Economist / Reporter
Economic Insight, Inc., Portland, OR
2004 – 2009
• Conducted analysis on natural gas costs and energy contract valuations. • Published and edited “Energy Market Report” newsletter tracking market dynamics. • Developed automated data workflows, improving analytical efficiency.

Sales and Marketing Manager
E-Business International, Inc., Beaverton, OR
2000 – 2002
• Managed supply chain strategies and client development. • Initiated and executed successful cross-border supply chain projects connecting U.S. companies with Chinese manufacturers.

Education
Bachelor of Science in Economics
University of Oregon, Eugene, OR
2003
Additional Information
• Technical Skills: Microsoft Office Suite, VBA, eViews • Languages: English (native)
• Professional Affiliations: Participant in CalCCA and other energy policy coalitions • Public Engagement: Regular contributor in public energy forums and stakeholder discussions

ATTACHMENT C
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TESTIMONY OF

THE CALIFORNIA COMMUNITY CHOICE ASSOCIATION

APPLICATION OF PACIFIC GAS AND ELECTRIC COMPANY FOR APPROVAL OF ELECTRIC RULE 30 FOR TRANSMISSION-LEVEL RETAIL ELECTRIC SERVICE A.24-11-007

SELECT DISCOVERY RESPONSES
ElectricRule30-Transmission-LevelInterconnections_DR_JointCCAs_001-Q001 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
Electric Rule 30 – Transmission-Level Interconnections
Application 24-11-007
Data Response
PG&E Data Request No.: JointCCAs_001-Q001
PG&E File Name: ElectricRule30-Transmission-LevelInterconnections_DR_JointCCAs_001-Q001 Request Date: January 23, 2025
Requester DR No.: 001
Requesting Party: JointCCAs
Requester: Scott Blaising
Date Sent: January 29, 2025
PG&E Witness(es): Karen Khamou Ornelas – Engineering, Planning and Strategy QUESTION 001
In its Prepared Testimony (“PG&E Testimony”), PG&E states that it “has seen a significant increase in applications for transmission level interconnections for new retail electric customers. Since 2023, PG&E has received 34 applications for transmission level service with demand of 4 MW or greater…. The total combined load of the 34 applications is 4,440 MW.” (PG&E Testimony at 1-4.)
a. For the 34 applications, please indicate whether (and if so, how and when) PG&E provided notice of the applications to the affected community choice aggregators (“CCAs”) in whose service area the new retail customers were to be located (“Potentially Affected CCA”).
b. Please describe the process that PG&E currently follows to provide notice to Potentially Affected CCAs of new applications for service by very large (i.e., 4 MW or greater) retail customers (“Mega Customers”).
c. As related to issues in this proceeding, is PG&E amenable to developing a formal procedure or amending its proposed Rule 30 to include a written process by which PG&E provides advance and continuing notice to Potentially Affected CCAs of applications for transmission service by Mega Customers? i. If not, please explain why PG&E is not amenable.
ii. If so, please further describe, including a description of what information PG&E would provide, when and under what terms and conditions.

ANSWER 001
a. The applications described in PG&E’s testimony concern the physical interconnection of a facility into PG&E’s electrical system. These applications do not concern the provision or procurement of electric commodity service. Thus, PG&E did not provide notice to energy providers such as Community Choice Aggregators (CCAs) or Direct Access (DA) providers. In addition, the applications Attachment C-1
ElectricRule30-Transmission-LevelInterconnections_DR_JointCCAs_001-Q001 Page 2 often include commercially sensitive customer information that is not shared outside of PG&E.
b. PG&E objects to term “mega customers” and will not use this terminology in its response. Subject to this objection, see subpart (a).
c. Given the issues in this proceeding and the need for a timely Commission determination on Electric Rule 30, PG&E does not believe that communications with CCAs or DA providers regarding new transmission level customer interconnections should be in scope in the proceeding. However, PG&E would be supportive of working with the CCAs and other procurement providers to develop written procedures regarding such communications and then submitting these procedures to the CPUC through a separate advice letter.

Attachment C-2
ElectricRule30-Transmission-LevelInterconnections_DR_JointCCAs_001-Q002 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
Electric Rule 30 – Transmission-Level Interconnections
Application 24-11-007
Data Response
PG&E Data Request No.: JointCCAs_001-Q002
PG&E File Name: ElectricRule30-Transmission-LevelInterconnections_DR_JointCCAs_001-Q002 Request Date: January 23, 2025
Requester DR No.: 001
Requesting Party: JointCCAs
Requester: Scott Blaising
Date Sent: January 29, 2025
PG&E Witness(es): Karen Khamou Ornelas – Engineering, Planning and Strategy QUESTION 002
In the PG&E Testimony, PG&E states that it “is presently conducting a pilot program for a cluster process for new transmission level retail electric customers located in Alameda and Santa Clara Counties.” (PG&E Testimony at 1-6.)
a. Please indicate whether the Potentially Affected CCAs have been informed of the pilot program. If so, please provide supporting information. b. Please provide further information on the pilot program, including (but not necessarily limited to) its intended results, its current status, whether Commission review is anticipated, and its relevance, if any, to PG&E’s request in this proceeding.
c. As related to issues in this proceeding, is PG&E amenable to including the Potentially Affected CCAs in a working group with PG&E for the purpose of providing timely, non-public information on the pilot program? i. If not, please explain why PG&E is not amenable.
ii. If so, please describe how PG&E might structure and implement a working group for the sharing of timely, non-public information about the pilot program.

ANSWER 002
a. See PG&E’s response to Question 1(a). Given that the Pilot Cluster Process involved the interconnection of new electric customers, not the procurement of the electric commodity, PG&E did not provide notice directly to Community Choice Aggregators (CCAs). However, PG&E has provided information in this proceeding regarding the Pilot Cluster Process which is equally available to CCAs. b. PG&E provided the following information in response to Cal Advocates Data Request Set #1, Question 6:

Attachment C-3
ElectricRule30-Transmission-LevelInterconnections_DR_JointCCAs_001-Q002 Page 2 In 2024, PG&E piloted a cluster study approach to study the increased number of data center applications received in the San Francisco South Bay area, mainly in Santa Clara and Alameda counties (“Pilot Cluster Process”). The clustering of large data center applications in certain areas and studying them in a serial process created complex, high-cost interconnection, and capacity upgrades. When projects are studied serially, the study timelines are lengthy and often do not study the cumulative impacts of the total load in a geographic area.

PG&E’s Pilot Cluster Process is a streamlined approach for handling applications for large data center loads within a specific geographic area, allowing customers to submit applications and be grouped based on their proximity to PG&E’s transmission and distribution system. We also offered customers with active or previously completed applications the chance to restudy, downsize, or change their project’s Point of Interconnection within the same calendar year. Customer Engagement Meetings have been or will be held during the Pilot Cluster Process to provide each customer a dedicated meeting where PG&E and the customer can discuss feasible connection options, available capacity, land, permitting, and planned capacity projects. This helps customers make informed decisions about proceeding with or withdrawing their applications.

The Pilot Cluster Process also sets clear timelines and procedures for study milestones, customer engagement, and project initiation.

Customers will be informed about the expected scope, costs, and duration of their project during the application phase. The Pilot Cluster Process aims to produce meaningful results that consider system capabilities and establish shared cost allocation and responsibility, supporting the development of a consolidated engineering and implementation plan.

PG&E expects that agreements that result from the Pilot Cluster Process will either be approved pursuant to the process proposed in PG&E’s interim implementation motion and/or through exceptional case filings at the Commission.
c. Given the issues in this proceeding and the need for a timely Commission determination on Electric Rule 30, PG&E does not believe that sharing non-public Pilot Cluster Process information with CCAs should be in scope in the proceeding. However, PG&E would be supportive of working with the CCAs on sharing information, subject to confidentiality protections, at the appropriate time in the Pilot Cluster Process.

Attachment C-4
ElectricRule30-Transmission-LevelInterconnections_DR_JointCCAs_001-Q006 Page 1

PACIFIC GAS AND ELECTRIC COMPANY
Electric Rule 30 – Transmission-Level Interconnections
Application 24-11-007
Data Response
PG&E Data Request No.: JointCCAs_001-Q006
PG&E File Name: ElectricRule30-Transmission-LevelInterconnections_DR_JointCCAs_001-Q006 Request Date: January 23, 2025
Requester DR No.: 001
Requesting Party: JointCCAs
Requester: Scott Blaising
Date Sent: January 29, 2025
PG&E Witness(es): Ben Moffat – Engineering, Planning and Strategy QUESTION 006
In Attachment A to Chapter 2 of the PG&E Testimony, PG&E sets forth a proposed rule that, among other things, contains the following definition for “Retail Service”: “Electric service to PG&E’s end-use or retail customers which is of a permanent and established character and may be continuous, intermittent, or seasonal in nature.” (PG&E Testimony at 2-AtchA-17.)
a. As related to issues in this proceeding, is PG&E amenable to changing the term “Retail Service” to “Retail Delivery Service” or another term that does not imply that the service described in Proposed Rule 30 relates to or includes generation service?
i. If not, please explain why PG&E is not amenable.
ii. If so, please provide a description of the revised term that PG&E agrees to use.

ANSWER 006
PG&E is willing to work with the Joint CCAs to clarify that the term “Retail Service” does not include or relate to generation service. As an initial proposal, PG&E suggests adding the following sentence to the defined term “Retail Service”:

For purposes of this Rule, Retail Service does not include or relate to providing generation service and/or the electric commodity.

Attachment C-5

Page 1 ends

PACIFIC GAS AND ELECTRIC COMPANY
Electric Rule 30 – Transmission-Level Interconnections
Application 24-11-007
Data Response
PG&E Data Request No.: JointCCAs_001-Q007
PG&E File Name: ElectricRule30-Transmission-LevelInterconnections_DR_JointCCAs_001-Q007 Request Date: January 23, 2025
Requester DR No.: 001
Requesting Party: JointCCAs
Requester: Scott Blaising
Date Sent: January 29, 2025
PG&E Witness(es): Ben Moffat – Engineering, Planning and Strategy QUESTION 007
In D.22-11-009, the Commission clarified that PG&E’s substation microgrid solutions “does not impact a customer’s choice of, or experience with, their [CCA].” (D.22-11-009 at 62.)
a. As related to issues in this proceeding, is PG&E amenable to providing advance notice to customers (at the earliest stages of the proposed Rule 30 process) that, among other things, identifies the CCA for the customer’s service location, describes the role that CCAs play in providing electric generation service to customers in their respective service areas, provides contact information (supplied by the CCA) for the CCA, and clearly states that the customer’s application for and election of transmission delivery service does not impact the customer’s rights with respect to electric generation service provided by the CCA? i. If not, please explain why PG&E is not amenable.
ii. If so, please identify where in the proposed Rule 30 stages PG&E would propose adding customer notification about these CCA-related matters.

ANSWER 007
PG&E is willing to work with the Joint CCAs to develop a procedure by which, during the Electric Rule 30 process, PG&E explains to an applicant that interconnection under Electric Rule 30 does not “impact a customer’s choice of, or experience with” a CCA or other energy provider such as a Direct Access provider. PG&E is willing to work with the Joint CCAs on the appropriate information to be provided by PG&E to potential transmission level customers during the Electric Rule 30 application process.

Attachment C-6
ElectricRule30-Transmission-LevelInterconnections_DR_JointCCAs_001-Q007

Page 1 ends

PACIFIC GAS AND ELECTRIC COMPANY
Electric Rule 30 – Transmission-Level Interconnections
Application 24-11-007
Data Response
Request Date: March 28, 2025
Requesting Party: Joint CCAs
Requester: Scott Blaising
Date Sent: April 10, 2025
QUESTION 001
Please provide a description of and associated timelines for expected activities under proposed Rule 30 (including, but not necessarily limited to, activity related to the submittal of an application, preliminary study, design review, engineering, interconnection agreement, procurement, construction and energization). The preceding examples are intended to be general descriptions of certain activity, and PG&E should not feel limited by these descriptions; PG&E may use whatever terminology it believes is most appropriate so long as PG&E’s response describes expected activities and provides associated timelines for these activities. As much as reasonably possible, the Joint CCAs request that PG&E describe activities in a sequential manner.

ANSWER 001
PG&E's large load interconnection process includes a number of phases: application, preliminary engineering study, design, preconstruction, construction, and closeout.

These phases can be described as the following:

Application Phase: The customer submits a service energization request and a study deposit.

Preliminary Engineering Phase: PG&E defines the initial scope of analysis and performs studies to determine service options and initial costs.

Design Phase: PG&E and the customer agree on the scope of work, creating a project design and refining the project cost.

Preconstruction Phase: This phase confirms dependencies between the customer and PG&E, including obtaining necessary permits and easements.

Construction Phase: PG&E schedules and completes all construction activities, including traffic control and scheduling outages.

Closeout Phase: All inspections are completed, and the site is energized, allowing the customer to start receiving service.

JointCCAs_003-Q001
Tyrone Hillman - Engineering, Planning and Strategy
Attachment C-7
ElectricRule30-Transmission-LevelInterconnections_DR_JointCCAs_003-Q001.pdf

Page 2 ends

While this process is generally sequential, certain components, such as design and preconstruction, can occur concurrently. The associated timelines are not solely under PG&E's control and depend on customer decisions, agency permit timelines, and land negotiations. As noted in our Application, until 2023, PG&E had a limited number of customers requesting retail electric service at transmission-level voltages. Infrequent requests for transmission-level interconnections were addressed through exceptional case filings. However, starting in 2023, the number of customers requesting transmission-level service began to significantly increase.

As we continue to refine our load interconnection processes, we lack the granularity to provide specific timelines for each phase. Nevertheless, the Preliminary Engineering Phase is planned to take 200 calendar days. Additionally, many projects require upstream capacity upgrades, which often involve more complex work. The CPUC has recently adopted the following maximum statewide timelines1 for upstream capacity projects, based on the lowest average among the three investor-owned utilities:

New or upgraded circuit: 684 calendar days
Substation upgrade: 1,021 calendar days
New substation: 3,242 calendar days.
1 D.24-09-020 at 47.

ElectricRule30-Transmission-LevelInterconnections_DR_JointCCAs_003-Q001.pdf JointCCAs_003-Q001
Tyrone Hillman - Engineering, Planning and Strategy
Attachment C-8

BEFORE THE PUBLIC UTILITIES COMMISSION

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

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

ON THE ORDER INSTITUTING RULEMAKING TO IMPROVE THE

CALIFORNIA CLIMATE CREDIT
Leanne Bober,
Director of Regulatory Affairs and Deputy
General Counsel
Willie Calvin,
Regulatory Case Manager

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
1121 L Street, Suite 400
Sacramento, CA 95814
Telephone: (510) 980-9459
E-mail: [email protected]
September 26, 2025
FILED
09/26/25
03:28 PM
R2507013
i

TABLE OF CONTENTS
I. INTRODUCTION ...............................................................................................................2 II. THE PRELIMINARY SCOPE SHOULD BE ADOPTED, WITH AMENDMENTS .......4 A. The Preliminary Scope Should be Amended to Incorporate AB 1207’s Climate Credit Revisions .........................................................................................5 B. Policy Objectives Developed by the Commission in Prior Climate Credit Proceedings Should be Revisited in Framing Current Priorities Associated with the Climate Credit ............................................................................................6 C. The Scope Should be Amended to Include the Development of a Standardized Method or Tool to Ensure Impacts of Climate Credit Proposals are Evaluated Against the Same Criteria .................................................6 III. CONCLUSION ....................................................................................................................7 ii

TABLE OF AUTHORITIES
Statutes
Cal. Pub. Util. Code Section 748.5 ............................................................................................. 4, 5 Cal. Pub. Util. Code Section 748.5(a)(1)-(2) .................................................................................. 4 Cal. Pub. Util. Code Section 748.5(b)(2) ........................................................................................ 3 Cal. Pub. Util. Code Section 745.8(a)(3) ........................................................................................ 3 Other Authorities
AB 1207 ................................................................................................................................. passim California Public Utilities Commission Decisions
D.12-12-033 ............................................................................................................................ 3, 5, 6 D.21-08-026 ............................................................................................................................ 3, 5, 6 California Public Utilities Commission Proceedings
R.11-03-012 .................................................................................................................................... 3 R.22-07-005 .................................................................................................................................... 3 R.25-07-013 ........................................................................................................................... passim California Public Utilities Commission Rulings
Administrative Law Judge’s Ruling Providing Guidance for Phase 1 Track A Proposals and Requesting Comments on a Consulting Services Proposal, R.22-07-005 (Jan. 17, 2023) ......... 3 SUMMARY OF RECOMMENDATIONS1
CalCCA recommends that in addition to the preliminary scoping items set forth in the OIR, the Commission should consider within the scope of this proceeding the following:
• Incorporating AB 1207 modifications to Cap-and-Invest and the Climate Credit; • Revisiting policy objectives and priorities established by the Commission in prior Climate Credit decisions to frame objectives and priorities in this proceeding; and • Developing a standardized method for evaluating Climate Credit modifications to inform customer bill impacts.
1 Acronyms used herein are defined in the body of this document.

BEFORE THE PUBLIC UTILITIES COMMISSION

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

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

ON THE ORDER INSTITUTING RULEMAKING TO IMPROVE THE

CALIFORNIA CLIMATE CREDIT
The California Community Choice Association2 (CalCCA) submits these comments pursuant to Rule 6.2 of the California Public Utilities Commission’s (Commission) Rules of Practice and Procedure,
3 in response to the Order Instituting Rulemaking to Improve the California Climate Credit4 (OIR), issued July 28, 2025. 2 California Community Choice Association represents the interests of 24 community choice electricity providers in California: Apple Valley Choice Energy, Ava Community Energy, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance of Southern California, CleanPowerSF, Desert Community Energy, Energy For Palmdale’s Independent Choice, Lancaster Energy, Marin Clean Energy, Orange County Power Authority, Peninsula Clean Energy, Pico Rivera Innovative Municipal Energy, Pioneer Community Energy, Pomona Choice Energy, Rancho Mirage Energy Authority, Redwood Coast Energy Authority, San Diego Community Power, San Jacinto Power, San José Clean Energy, Santa Barbara Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power, and Valley Clean Energy. 3 State of California Public Utilities Commission, Rules of Practice and Procedure, California Code of Regulations Title 20, Division 1, Chapter 1 (May 2021): https://webproda.cpuc.ca.gov/- /media/cpuc-website/divisions/administrative-law-judge-division/documents/rules-of-practice-and-procedure-may-2021.pdf. 4 Order Instituting Rulemaking to Improve the California Climate Credit, Rulemaking (R.) 25-07- 013 (July 28, 2025):
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M574/K655/574655670.PDF. 2 I. INTRODUCTION
On September 19, 2025, Governor Gavin Newsom signed into law an extension through 2045 of Cap-and-Invest, rebranded from its previous name, Cap-and-Trade.5 Proceeds from Cap-and-Invest are provided to customers through the California Climate Credit, implemented by the Commission to “protect state utility ratepayers, encourage[] decarbonization of the state’s economic sectors, and further enable[] Californians to affordably decarbonize and power their end uses.”6
In addition, qualifying emissions-intensive-trade-exposed (EITE) customers receive California Industry Assistance (CIA) to minimize “leakage” of emissions (production moving out of state) by offsetting a portion of the costs of the Cap-and-Trade (Invest) program built into electric prices.

The OIR’s preliminary scope includes important questions regarding: (1) whether the Commission should modify eligibility for customers receiving the Climate Credit; (2) how and when the Climate Credit should be distributed; (3) how Climate Credit changes should be communicated to customers; and (4) whether the Commission should modify the CIA.7 CalCCA supports these preliminary scoping items, with the following three additions.

First, the Commission should consider the Assembly Bill (AB) 1207 updates to Cap-and-Trade and the Climate Credit and incorporate any necessary changes in the Climate Credit Program. These updates include rebranding to Cap-and-Invest, the extension of Cap-and-Invest from 2030 through 2045, the establishment of an upper bound of four payments per year for 5 Governor Newsom Signs Historic Package of Bipartisan Legislation Saving Billions on Electric Bills, Stability Gas Market and Cutting Pollution (Sept. 19, 2025) (Governor Gavin Newsom Press Release), located at https://www.gov.ca.gov/2025/09/19/governor-newsom-signs-historic-package-of-bipartisan-legislation-saving-billions-on-electric-bills-stabilizing-gas-market-and-cutting-pollution/; see Assembly Bill (AB) 1207 (Irwin, Chapter 117, Statutes of 2025) (updates to Cap-and-Trade program): Bill Text - AB-1207 Climate change: market-based compliance mechanism: extension. 6 Governor Gavin Newsom Press Release, see supra., n.6. 7 OIR, at 5-6.
3 dispersal of the Climate Credit, and setting a deadline of January 1, 2027, for the investor-owned utilities (IOUs) to update customer Climate Credit outreach plans.8 Second, the Commission should revisit the Climate Credit policy objectives and priorities originally adopted with substantial stakeholder input in Decision (D.) 12-12-033,9 and affirmed in D.21-08-026.10 Among other objectives, the Commission prioritized reducing adverse impacts on low-income households, maintaining competitive neutrality across load serving entities, preserving the carbon price signal, and preventing economic leakage. 11 Revisiting the objectives
and determining current priorities will assist in framing stakeholder positions on potential Climate Credit modifications.

Third, the Commission should develop a standardized method of evaluating the effects of any proposed modifications to Climate Credit eligibility or allocation. Different stakeholders may prioritize different groups of customers and may advocate for modifications that benefit certain groups over others. Effectively analyzing and comparing impacts across customer groups is therefore critical to ensuring a fulsome evaluation of potential outcomes in this proceeding.

For example, the Commission could develop a calculator for stakeholders to estimate bill impacts similar to the calculator developed in the Demand Flexibility proceeding (R.22-07-005) to assess proposals related to the income-graduated fixed charge (IGFC). 12 In that proceeding, all
8 AB 1207 (amending Public Utilities Code sections 745.8(a)(3) and 748.5(b)(2)). All section references herein are to the Public Utilities Code, unless otherwise noted. 9 D.12-12-033, Decision Adopting Cap-and-Trade Greenhouse Gas Allowance Revenue Allocation Methodology for the Investor-Owned Electric Utilities, R.11-03-012 (Dec. 20, 2012):
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M040/K631/40631611.PDF. 10 D.21-08-026, Decision Adopting Customer Climate Credit Updates, R.20-05-002 (Aug. 19, 2021): https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M402/K296/402296732.PDF. 11 Id. at 12-13. 12 See Administrative Law Judge’s Ruling Providing Guidance for Phase 1 Track A Proposals and Requesting Comments on a Consulting Services Proposal, R.22-07-005 (Jan. 17, 2023), at 3 (explaining the staff guidance memo, which proposes to develop a spreadsheet tool for analyzing the volumetric rate 4 proposals were presented with standardized metrics, ensuring stakeholders and the Commission could easily compare proposals and their impacts.

As set forth below, CalCCA recommends that in addition to the OIR preliminary scoping items, the Commission should consider the following:
• Incorporating AB 1207 modifications to Cap-and-Invest and the Climate Credit; • Revisiting policy objectives and priorities established by the Commission in prior Climate Credit decisions to frame objectives and priorities in this proceeding; and • Developing a standardized method for evaluating Climate Credit modifications to inform customer bill impacts.

Finally, CalCCA has no objections to the preliminary schedule, preliminary determination on categorization of the proceeding as quasi-legislative, and the preliminary determination that no evidentiary hearings will be necessary.

II. THE PRELIMINARY SCOPE SHOULD BE ADOPTED, WITH AMENDMENTS The OIR preliminary scope should be adopted, with amendments. Items currently in the preliminary scope will ensure the Commission and stakeholders examine the effectiveness of the Climate Credit and its impact on customer affordability through: (1) considering eligibility for the climate credit among customer groups, listed in section 748.5,13 but which the Commission states it “has defined eligibility among those customers in previous decisions”; (2) adjustment of the timing, number, or method for allocation of Climate Credit funds; (3) customer education and outreach regarding changes to the allocation or distribution; and (4) considering whether the California Industry Assistance for EITE customers should be modified. In addition to these impact associated with a chosen fixed charge):
https://docs.cpuc.ca.gov/SearchRes.aspx?DocFormat=ALL&DocID=501282388. The income-graduated fixed charge is now called the base services charge.
13 Section 748.5 requires all Cap-and-Invest revenues (other than revenues set aside for certain energy efficiency and other programs) to be credited directly to IOU residential customers and allows the Commission to also credit revenues to small businesses and EITE customers. Section 748.5(a)(1)-(2). 5 scoping items, and as discussed more fully below, the Commission consider: (1) changes to the Cap-and-Invest and Climate Credit programs adopted by AB 1207; (2) revisiting the Climate Credit policy objective and priorities adopted in D.12-12-033 and D.21-08-026; and (3) adopting a standardized tool to measure the impact of potential modifications to the Climate Credit.

A. The Preliminary Scope Should be Amended to Incorporate AB 1207’s Climate Credit Revisions
The Commission should consider changes to the Cap-and-Invest and Climate Credit programs recently adopted in AB 1207. First, in addition to rebranding the Cap-and-Trade program to Cap-and-Invest, AB 1207 extends Cap-and-Invest through 2045.14 Second, Climate Credits are to be provided to residential customers on bills “in no more than four high-billed months of each year to maximize customer electric bill affordability, or as otherwise directed by the [C]omission to address extreme, unforeseen, and temporary circumstances.”15 Third, not later than January 1, 2027, the Commission must require the IOUs:
to update the customer outreach plan … to include a statement at the top of customer bills in applicable months specifying the amount of money saved on a utility bill in that month and attributing those savings to the climate credit and the California Cap-and-Invest Program.16
These and other AB 1207 updates to the Cap-and-Invest and Climate Credit programs should be incorporated into any changes by the Commission to the Climate Credit program. 14 AB 1207 (amending Health and Safety Code, section 38501(b)(4)). 15 Id. (amending Section 748.5(a)(2)).
16 Id. (amending Section 748.5(b)(2)).
6 B. Policy Objectives Developed by the Commission in Prior Climate Credit Proceedings Should be Revisited in Framing Current Priorities Associated with the Climate Credit
Policy objectives established by the Commission in D.12-12-033,17 and most recently affirmed in D.21-08-026,18 should be revisited to frame current priorities associated with the Climate Credit. These objectives, for which the Commission ultimately gave the same prioritization in both decisions, include:
• Preserving the carbon price signal. (High Priority)
• Preventing economic leakage. (High Priority)
• Reducing adverse impacts on low-income households. (High Priority) • Maintaining competitive neutrality across load serving entities. (High Priority) • Distributing revenues equitably recognizing the public asset nature of the atmospheric carbon sink. (Medium Priority)
• Achieving administrative simplicity and understandability. (Medium Priority) • Correcting for market failures that lead to underinvestment in carbon mitigation activities and technologies. (Low Priority).19
The Commission should again require parties to comment on the content of these policy objectives to determine if the objectives still apply, whether additional objectives should be considered, and the prioritization by parties of the objectives. Understanding stakeholder views on each objective can help frame and inform modifications to the Climate Credit as suggested in the preliminary scope.

C. The Scope Should be Amended to Include the Development of a Standardized Method or Tool to Ensure Impacts of Climate Credit Proposals are Evaluated Against the Same Criteria
The Commission should add to the scope the development of a standardized method of evaluating party proposals to modify the implementation of the Climate Credit. Similar to the 17 D.12-12-033, at 191, Conclusion of Law (COL) 8.
18 D.21-08-026, at 60, COL 3. 19 D.12-12-036, at 69-70; D.21-08-026, at 12-13. 7 Commission’s development of a bill impact calculator for party proposals for the IGFC in the Demand Flexibility proceeding, the Commission should develop a tool or rubric to compare Climate Credit proposals. Standardized outputs from a tool will provide a streamlined way to compare proposals and ensure all stakeholders understand the tradeoffs and impacts.

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

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

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
September 26, 2025

MCE Board of DirectorsNovember 20, 2025

MCE Board of Directors
November 20, 2025