Record of Testimony: Kyra J. Coyle
UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR
1. El Paso Electric
Company
SOAH Docket No. 473-
25-11219
PUC Docket No. 57568
Application of El Paso Electric
Company for Authority to Change
Rates
Public Utility Commission of
Texas
Office of Public Utility
Counsel (OPUC)
2025
2. Southwestern Electric
Power Company
SOAH Docket No. 473-
24-22136
PUC Docket No. 56643
Application of Southwestern
Electric Power Company for
Authority to Reconcile Fuel Costs
Public Utility Commission of
Texas
OPUC 2025
3. CenterPoint Energy
Houston Electric, LLC
SOAH Docket No. 473-
25-05323
PUC Docket No. 57271
Application of CenterPoint Energy
Houston Electric, LLC for
Determination of System
Restoration Costs
Public Utility Commission of
Texas
OPUC 2025
4. PacifiCorp Docket No. 24-035-04 Application of Rocky Mountain Power for Authority to Increase Its
Retail Electric Utility Service Rates
in Utah and for Approval of Its
Proposed Electric Service
Schedules and Electric Service
Regulations
Public Service Commission
of Utah
Stadion, LLC 2024
5. PacifiCorp Docket No. UE 433 PacifiCorp d/b/a Pacific Power Request for General Rate Revision
Public Utility Commission of
Oregon
Vitesse, LLC 2024
6. CenterPoint Energy
Houston Electric, LLC
SOAH Docket No. 473-
24-13232
PUC Docket No. 56211
Application of CenterPoint Energy
Houston Electric, LLC for Authority
to Change Rates
Public Utility Commission of
Texas
OPUC 2024
7. Constellation Mystic
Power, LLC.
Docket No. ER18-1639-
027
Annual Fixed Revenue
Requirement, Capital Expense
Recovery, and Stipulated Variable
Cost Recovery for Mystic 8 & 9
Fuel Security System
Federal Regulatory
Commission
Eastern New England
Consumer-Owned Systems
(ENECOS)
2024
8. Peoples Gas Light and
Coke Company
Docket No. 23-0069 Proposed General Increase in Gas
Rates and Revisions to Other
Terms and Conditions of Service
Illinois Commerce
Commission
City of Chicago 2024
Record of Testimony: Kyra J. Coyle
UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR
9. Southern Indiana Gas
and Electric Company
DBA CenterPoint
Energy Indiana South
Cause No. 45990 Authority to Modify its Rates and
Charges for Electric Utility Service
Through a Phase-In of Rates…
Indiana Utility Regulatory
Commission
SABIC Innovative Plastics
Mount Vernon, LLC
2024
10. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-228-
EN-23
Certificate of Public Convenience
and Necessity to Construct and
Operate a New 115 kV Substation,
Two New 115 kV Transmission
Lines, Modification and Extension
of Four 115 kV Transmission
Lines, Four New 115 kV Load-Serving Transmission Lines and Related Facilities
Wyoming Public Service
Commission
--
2023
11. Black Hills Power, Inc.
DBA Black Hills Energy
Docket No. 20002-131-
EA-23
Proposed Modification of the Neil
Simpson II Generation Facility to a
Dual Fuel Source and Request for
a Determination Regarding the
Need to File for a Certificate of
Public Convenience and Necessity
Wyoming Public Service
Commission
-- 2023
12. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-225-
EM-23
Authority to Increase Its Power
Cost Adjustment by $0.00872 per
Kilowatt Hour
Wyoming Public Service
Commission
-- 2023
13. Cheyenne Light, Fuel,
and Power Company
and Black Hills Power,
Inc. DBA Black Hills
Energy
Docket No. 20003-223-
ET-23
Authority to Establish a Low-Carbon Surcharge Tariff and RateWyoming Public Service Commission
-- 2023
14. Cheyenne Light, Fuel,
and Power Company
and Black Hills Power,
Inc. DBA Black Hills
Energy
Docket No. 20002-127-
ET-23
Authority to Establish a Low-Carbon Surcharge Tariff and RateWyoming Public Service Commission
-- 2023
15. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-221-
EA-23
Establish Intermediate Low-Carbon Portfolio Standards and Requirements
Wyoming Public Service
Commission
-- 2023
Record of Testimony: Kyra J. Coyle
UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR
16. Black Hills Power, Inc.
DBA Black Hills Energy
Docket No. 20002-126-
EA-23
Establish Intermediate Low-Carbon Portfolio Standards and Requirements
Wyoming Public Service
Commission
-- 2023
17. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-217-
EM-23
Authority to Decrease Its Power
Cost Adjustment by $0.03149 per
Kilowatt-Hour
Wyoming Public Service
Commission
-- 2023
18. Black Hills Wyoming
Gas, LLC DBA Black
Hills Energy
Docket No. 30026-78-
GR-23
Authority to Implement a General
Rate Increase of $19,262,412 per
Annum and Extend Its Wyoming
Integrity Rider
Wyoming Public Service
Commission
-- 2023
19. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-214-
ER-22
A General Rate Increase of
$15,366,026 per Annum and
Authority to Revise Its Power Cost
Adjustment Mechanism
Wyoming Public Service
Commission
-- 2022
20. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-213-
EM-22
Authority to Increase Its Power
Cost Adjustment by $0.00129 per
Kilowatt-Hour
Wyoming Public Service
Commission
-- 2022
21. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-211-
EM-22
Authority to Pass on a Blockchain
Interruptible Service Customer
Credit Adjustment Rate of $0.00
per Kilowatt-Hour Effective June 1,
2022
Wyoming Public Service
Commission
-- 2022
22. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-210-
ET-22
Revise the Demand Side
Management Surcharge Rate,
Effective June 1, 2022
Wyoming Public Service
Commission
-- 2022
23. Cheyenne Light, Fuel,
and Power Company
and Black Hills Power,
Inc. DBA Black Hills
Energy
Docket No. 20003-209-
EA-22
Establish Intermediate Low-Carbon Energy Portfolio
Standards and Requirements
Wyoming Public Service
Commission
-- 2022
Record of Testimony: Kyra J. Coyle
UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR
24. Cheyenne Light, Fuel,
and Power Company
and Black Hills Power,
Inc. DBA Black Hills
Energy
Docket No. 20002-123-
EA-22
Establish Intermediate Low-Carbon Energy Portfolio
Standards and Requirements
Wyoming Public Service
Commission
-- 2022
25. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-208-
EA-22
Authority to Increase Its Voluntary
Renewable Energy Rider Rate to
$0.47 per Month per 100-KWh
Block, Effective April 1, 2022
Wyoming Public Service
Commission
-- 2022
26. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-206-
EN-22
A Certificate of Public
Convenience and Necessity to
Construct and Operate One New
230 kV Substation, Two
Replacement 115 kV Substations,
Three 230 kV Transmission Lines,
Two 115 kV Transmission Lines
and Related Facilities in Converse,
Laramie, Goshen and Platte
Counties on Wyoming and Scotts
Bluff County in Nebraska
Wyoming Public Service
Commission
-- 2022
27. Black Hills Wyoming
Gas, LLC DBA Black
Hills Energy
Docket No. 30026-68-
GM-22
Authority to Implement Wyoming
Integrity Rider Rates of $0.0231
per Therm for Residential General
Service, $0.0139 per Therm for
Small General Service, $0.0148
per Therm for Medium General
Service, $0.0092 per Therm for
Large General Service, and
$0.0285 per Therm for On-System
Transportation Service
Wyoming Public Service
Commission
-- 2022
28. Black Hills Wyoming
Gas, LLC DBA Black
Hills Energy
Docket No. 30026-67-
GM-22
Authority to Decrease the
Revenue Adjustment Mechanism
Rate By $0.0058 per Therm
Wyoming Public Service
Commission
-- 2022
Record of Testimony: Kyra J. Coyle
UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR
29. Black Hills Wyoming
Gas, LLC DBA Black
Hills Energy
Docket No. 30026-66-
GP-22
Authority to Pass on a Gas Cost
Rate Decrease of $0.1155 per
Therm
Wyoming Public Service
Commission
-- 2022
30. Black Hills Wyoming
Gas, LLC DBA Black
Hills Energy
Docket No. 30026-65-
GN-22
Determination of CPCN
Requirements Regarding the
Relocation of an Existing
Transmission Pipeline and Related
Facilities
Wyoming Public Service
Commission
-- 2022
31. Black Hills Wyoming
Gas, LLC DBA Black
Hills Energy
Docket No. 30026-63-
GP-22
Authority to Pass on a Gas Cost
Rate Decrease of $0.0026 per
Therm
Wyoming Public Service
Commission
-- 2022
32. Black Hills Wyoming
Gas, LLC DBA Black
Hills Energy
Docket No. 30026-60-
GM-22
Authority to Increase the Revenue
Adjustment Mechanism Rate by
$0.0022 Per Therm
Wyoming Public Service
Commission
-- 2022
33. Black Hills Wyoming
Gas, LLC DBA Black
Hills Energy
Docket No. 30026-57-
GT-22
Authority to Decrease the Energy
Efficiency Surcharge for
Residential Customers by $0.0034
per Therm and Increase It by
$0.0006 per Therm for Non-Residential Customers
Wyoming Public Service
Commission
-- 2022
34. Black Hills Wyoming
Gas, LLC DBA Black
Hills Energy
Docket No. 30026-55-
GP-22
Authority to Pass on a Wholesale
Gas Cost Increase of $0.0669 per
Therm
Wyoming Public Service
Commission
-- 2022
35. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-205-
ET-21
Approval of the 2022-2024
Demand Side Management
Program Plan by November 1,
2021, for Implementation on
January 1, 2022
Wyoming Public Service
Commission
-- 2021
36. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-203-
EM-21
Authority to Pass on a Blockchain
Interruptible Service Customer
Credit Adjustment Rate Of $0.00
Per KWh Effective June 1, 2021
Wyoming Public Service
Commission
-- 2021
Record of Testimony: Kyra J. Coyle
UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR
37. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-202-
EM-21
Authority to Increase Its Power
Cost Adjustment by $0.00246 per
Kilowatt-Hour
Wyoming Public Service
Commission
-- 2021
38. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-201-
EN-21
Certificate of Public Convenience
and Necessity to Construct and
Operate Two 115 kV Substations,
Associated Transmission Lines,
and Related Facilities in Laramie
County, Wyoming
Wyoming Public Service
Commission
-- 2021
39. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-200-
ET-21
Authority to Update Its Demand
Side Management Surcharge Rate,
Effective June 1, 2021
Wyoming Public Service
Commission
-- 2021
40. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-199-
EA-21
Authority to Increase Its Voluntary
Renewable Energy Rider Rate to
$0.43 per Month per 100-KWh
Block, Effective April 1, 2021
Wyoming Public Service
Commission
-- 2021
41. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-198-
EN-21
Certificate of Public Convenience
and Necessity to Construct and
Operate a 115 kV Substation,
Associated Transmission Lines,
and Related Facilities in Laramie
County, Wyoming
Wyoming Public Service
Commission
-- 2021
42. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-194-
EM-20
Authority to Increase Its Power
Cost Adjustment by $0.00243 per
Kilowatt-Hour Effective July 1,
2020
Wyoming Public Service
Commission
-- 2020
43. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-193-
EN-20
Certificate of Public Convenience
and Necessity to Rebuild an
Existing 115 kV Transmission Line
from Skyline Substation to East
Business Park Substation in
Laramie County, Wyoming
Wyoming Public Service
Commission
-- 2020
Record of Testimony: Kyra J. Coyle
UTILITY PROCEEDING SUBJECT BEFORE CLIENT YEAR
44. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-190-
ET-20
Authority to Update Its Tariff
Applicable to the Demand Side
Management Margin Revenue
Recovery, the Balancing Account
and Program Costs
Wyoming Public Service
Commission
-- 2020
45. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-188-
ET-20
Authority to Decrease Its Electric
Voluntary Renewable Energy Rider
Rate to $0.03 per Month per 100-
KWh Block
Wyoming Public Service
Commission
-- 2020
46. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-182-
ET-19
Authority to Update Its Electric
and Gas Tariffs Applicable to the
Demand Side Management
Margin Revenue Recovery, the
Balancing Account and Program
Costs
Wyoming Public Service
Commission
-- 2019
47. Cheyenne Light, Fuel,
and Power Company
DBA Black Hills Energy
Docket No. 20003-173-
ET-18
Authority to Implement a
Blockchain Interruptible Service
Tariff
Wyoming Public Service
Commission
-- 2018
Attachment KJC-2
PG&E Responses to PCE Data Requests
BillingModernization_DR_PCE_001-Q001Supp01 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_001-Q001
PG&E File Name: BillingModernization_DR_PCE_001-Q001Supp01 Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: April 15, 2025
Supp01: April 22, 2025
PG&E Witness(es):
QUESTION 001
Please provide all workpapers associated with PG&E’s Application and Prepared Testimony, including all confidential workpapers.
ANSWER 001 SUPPLEMENTAL 01
An attachment to this response contains CONFIDENTIAL information provided pursuant to the Non-Disclosure Agreement between PG&E and Peninsula Clean Energy Authority dated April 22, 2025 in this proceeding.
Please see “BillingModernization_DR_PCE_001-Q001Supp01Atch01CONF.zip” for the confidential workpapers.
ANSWER 001
Please see “BillingModernization_DR_PCE_001-Q001Atch01.zip” for the public workpapers. PG&E can supplement with confidential workpapers once it receives a signed Non Disclosure Agreement.
Line Revenue Requirement Summary by Capital and Expense 2023 2024 2025 2026 2027 2028 2029 2030 2023-2030
1 Capital Revenue Requirement $0 $1,724,426 $9,976,643 $36,792,969 $59,157,475 $53,713,725 $29,757,165 $120,085,303 $311,207,706 2 Expense Revenue Requirement $804,392 $3,929,281 $6,995,416 $12,041,923 $7,105,522 $8,191,219 $23,306,117 $19,567,626 $81,941,496 3 Total RRQ (without RF&U) [1] $804,392 $5,653,707 $16,972,058 $48,834,893 $66,262,997 $61,904,944 $53,063,282 $139,652,929 $393,149,203 Revenue Requirement Summary by Functional Area
RRQ by Functional Area (Supports Table 7-4 in Opening Testimony) 2023 2024 2025 2026 2027 2028 2029 2030 2023-2030 4 Electric Distribution (ED) $344,930 $2,424,356 $7,886,196 $24,761,634 $33,598,519 $31,388,777 $26,905,630 $70,810,737 $198,120,780 5 Electric Generation (EG) $190,365 $1,337,992 $2,933,454 $4,755,492 $6,452,623 $6,028,240 $5,167,248 $13,599,260 $40,464,675 6 Gas Distribution (GD) $182,239 $1,280,877 $4,166,569 $13,082,488 $17,751,342 $16,583,853 $14,215,241 $37,411,934 $104,674,544 7 Gas Transmission & Storage (GT&S) $86,858 $610,482 $1,985,839 $6,235,278 $8,460,513 $7,904,073 $6,775,162 $17,830,998 $49,889,203 9 Total RRQ (without RF&U)[1] $804,392 $5,653,707 $16,972,058 $48,834,893 $66,262,997 $61,904,944 $53,063,282 $139,652,929 $393,149,203 10 Fuctional Area Allocation Percentages Alloc Fctr 2023 Alloc Fctr 2024 Alloc Fctr 2025 Alloc Fctr 2026 Alloc Fctr 2027 Alloc Fctr 2028 Alloc Fctr 2029 Alloc Fctr 2030 11 Electric Distribution (ED) 38.772% 38.772% 41.679% 45.058% 45.058% 45.058% 45.058% 45.058% 12 Electric Generation (EG) 21.398% 21.398% 15.504% 8.653% 8.653% 8.653% 8.653% 8.653% 13 Gas Dsitribution (GD) 20.484% 20.484% 22.021% 23.806% 23.806% 23.806% 23.806% 23.806% 14 Gas Transmission and Storage (GT&S) 9.763% 9.763% 10.495% 11.346% 11.346% 11.346% 11.346% 11.346% 15 Electric Transmission (ET) [2] 9.583% 9.583% 10.302% 11.137% 11.137% 11.137% 11.137% 11.137% 16 Total[1] 90.417% 90.417% 89.698% 88.863% 88.863% 88.863% 88.863% 88.863% 17 RRQ by Program 2023 2024 2025 2026 2027 2028 2029 2030 2023-2030 18 Billing Cloud Service (BCS) $0 $904,171 $5,301,195 $31,396,240 $26,651,053 $25,450,807 $24,127,031 $22,310,480 $136,140,978 19 Customer Care and Billing (CC&B) 25.1 $0 $26,930 $4,505,887 $5,321,987 $27,988,139 $24,398,518 $23,334,864 $20,719,569 $106,295,895 20 Customer-to-Meter (C2M) $804,392 $4,722,606 $7,164,976 $12,116,665 $11,623,805 $12,055,619 $5,601,387 $96,622,880 $150,712,330 21 Total RRQ (without RF&U)[1] $804,392 $5,653,707 $16,972,058 $48,834,893 $66,262,997 $61,904,944 $53,063,282 $139,652,929 $393,149,203 Notes
[1]
[2] Electric Transmission (ET) allocation percentages are provided for illustrative purposes.
Total RRQ (Supports Table 7-1 in Opening Testimony)
Excludes Electric Transmission (ET) - This filing excludes costs allocated to Electric Transmission, which are recovered under separate FERC-jurisdictional Transmission Owner (TO) cases.
BillingModernization_DR_PCE_001-Q003 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_001-Q003
PG&E File Name: BillingModernization_DR_PCE_001-Q003
Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: April 18, 2025
PG&E Witness(es): Matt Hedges – Information Technology
QUESTION 003
Referring to PG&E’s Application at pp. 7-8:
a. Please confirm that the Oracle billing system CC&B 25.1 that PG&E proposes to implement during the second stage of its BMI implementation plan will be replaced by the implementation of Oracle’s C2M product during the third stage of PG&E’s BMI implementation plan. If not confirmed, please explain. b. If part (a) is confirmed, please provide PG&E’s justification for implementing the CC&B 25.1 system when the CC&B 25.1 system will eventually be replaced by the C2M product during the third phase of PG&E’s BMI implementation plan. c. If part (a) is confirmed, please explain if it was feasible for PG&E to have upgraded its billing system directly from the CC&B 2.4 system to the C2M product without having to implement the CC&B 25.1 upgrade. Additionally, please explain if PG&E explored or considered this alternative option, providing any analyses conducted to explore this option.
ANSWER 003
a. Confirmed. PG&E’s current plan based on the market analysis completed by both Accenture and Utilligent indicate that C2M is the target state solution. PG&E plans to re-evaluate that assessment at the end of Stage 2 (CC&B 25.1). b. Within PG&E’s prepared testimony Chapter 4, p. 4-26 through p. 4-34, various upgrade paths are discussed along with PG&E rationale to include CC&B 25.1 into the upgrade path.
c. Please refer to response “b” above.
BillingModernization_DR_PCE_001-Q005 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_001-Q005
PG&E File Name: BillingModernization_DR_PCE_001-Q005
Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: April 18, 2025
PG&E Witness(es): Matt Hedges – Information Technology
QUESTION 005
Referring to PG&E’s Application at pp. 9-10:
a. Please outline the specific “investments related to the BCS and CC&B 25.1 upgrade that will not be utilized in the final C2M end state system.” Additionally, please explain why these investments are necessary and why they will not be used in the C2M end state system.
b. Please provide the costs associated with the specific investments outlined in part (a).
ANSWER 005
a. The BCS project can be broadly divided into functionality related to rate calculation and functionality related to interfaces. The major interface functionality relates to interfacing between BCS and CC&B and other systems. These interfaces are necessary to exchange and update information between systems for purposes of billing, bill presentment, reporting, and others. When C2M replaces BCS, these interfaces will no longer be necessary.
For CC&B 25.1, the work can broadly be divided into hardware, integration, and system component upgrades. The hardware and integration work will be usable in C2M, while 75 percent of the system component upgrades will be used in C2M, as C2M will replace much of the customizations and introduce some new system features compared to CC&B. The components are necessary for the CC&B 25.1 project because they are needed for CC&B to perform correctly. b. For BCS, PG&E estimates the interface work to be 40 percent of the total capital investment, or $49.9 million.
For CC&B 25.1, PG&E estimates 25 percent of the system component upgrade cost, or $24.7 million.
BillingModernization_DR_PCE_001-Q006 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_001-Q006
PG&E File Name: BillingModernization_DR_PCE_001-Q006
Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: April 18, 2025
PG&E Witness(es): Matt Hedges – Information Technology
QUESTION 006
Referring to PG&E’s Prepared Testimony, Chapter 2, p. 2-6, lines 16 to 34, and p. 2-7, lines 1 to 2: Please confirm if improvements to the Third-Party Energy Service Provider Management system under PG&E’s BMI will lead to lower CCA service fees. If confirmed, please explain, outlining the specific CCA service fees that will be lowered and the estimated reduction amount for each service fee.
ANSWER 006
While PG&E’s BMI (Billing Modernization Initiative), including the transition to the C2M platform, is expected to improve efficiency in managing and supporting third-party energy service providers such as Community Choice Aggregators (CCAs), it is not possible at this time to confirm whether those improvements will directly result in lower CCA service fees.
Although the new C2M platform introduces streamlined processes, reduced reliance on manual interventions, and consolidated systems, which collectively create operational efficiencies the potential impact on CCA service fees is subject to several factors. These include regulatory requirements, future operational needs, and unforeseen system complexities that may emerge as the new platform is implemented and scaled.
BillingModernization_DR_PCE_001-Q010 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_001-Q010
PG&E File Name: BillingModernization_DR_PCE_001-Q010
Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: April 18, 2025
PG&E Witness(es): Matt Hedges – Information Technology
QUESTION 010
Referring to PG&E’s Prepared Testimony, Chapter 2, p. 2-18, lines 14 to 16, and p. 2-19, lines 1 to 13:
a. Please explain any expected differences in the presentation of bill components or rates for bundled and CCA customer bills between PG&E’s current bill presentment structure and the new bill presentment structure under PG&E’s BMI. b. Please explain how the PCIA rate will be presented on bundled and CCA customer bills through the new bill presentment structure under PG&E’s BMI, compared to PG&E’s current bill presentment structure.
c. Please explain if the upgrades proposed under PG&E’s BMI will enable both bundled and CCA customer bills to show the customer’s kWh Usage and $/kWh Rate used to determine the monthly PCIA.
d. If subpart (c) is confirmed, please identify the upgrades that will enable this PCIA bill presentment and identify the stage in which those upgrades will be implemented. e. If subpart (c) is confirmed, please explain whether PG&E will adopt a bill presentment structure showing both bundled and CCA customers’ kWh Usage and $/kWh Rate used to determine the monthly PCIA charge. If not, please explain why not.
ANSWER 010
a. At this stage of PG&E’s Billing Modernization Initiative, we are still several years away from reaching Stage 3 (our target state) where the full capabilities of the new system including enhancing bill presentment will be implemented. Because the system design and customer bill format are still in the initial stages, we cannot yet confirm what specific changes in bill presentment will look like for bundled versus CCA customers. With that said, PG&E’s initial review of the bill extract functionality from the C2M product indicates that the functionality allows for increased flexibility. If BillingModernization_DR_PCE_001-Q010 Page 2
that turns out to be true, PG&E would work with CCAs for bill presentment improvements.
b. As with other billing elements, the way in which the PCIA (Power Charge Indifference Adjustment) is presented may change under the new system. However, at this point in the Initiative, we are not able to confirm whether or how the presentation will differ from the current format.
c. The project is still in the early stages, and we are several years away from reaching Stage 3, the target state where the system’s full bill presentment functionality will be implemented. At this time, it is too early to confirm whether customer bills for either bundled or CCA customers will display both the kwh usage and specific price per kWh rate used to calculate the monthly PCIA charge.
d. See response for c.
e. See response for c.
BillingModernization_DR_PCE_001-Q011 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_001-Q011
PG&E File Name: BillingModernization_DR_PCE_001-Q011
Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: April 18, 2025
PG&E Witness(es): Matt Hedges – Information Technology
QUESTION 011
Referring to PG&E’s Prepared Testimony, Chapter 2, p. 2-18, lines 14 to 16, and p. 2-19, lines 1 to 13: Please explain any expected differences in the presentation of CARE and FERA discounts for bundled and CCA customer bills between PG&E’s current bill presentment structure and the new bill presentment structure under PG&E’s BMI.
ANSWER 011
At this point, it is too early to confirm what changes, if any, will be made to the presentation of CARE and FERA discounts or how those changes might differ between bundled and unbundled customer bills. As we move closer to Stage 3, PG&E will have more clarity on potential upgrades to bill formatting and discount display.
BillingModernization_DR_PCE_001-Q013 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_001-Q013
PG&E File Name: BillingModernization_DR_PCE_001-Q013
Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: April 18, 2025
PG&E Witness(es): Emily Bartman – Customer and Enterprise Solutions Matt Hedges – Information Technology
QUESTION 013
Referring to PG&E’s Prepared Testimony, Chapter 4 at Table 4-1: Please identify the specific rate implementation projects or updates to rate schedules that are on-hold due to the need for billing system upgrades, as proposed under PG&E’s BMI.
ANSWER 013
Please see Table 1 below for identification of the specific rate implementation projects or updates to rate schedules that are, as of 4/17/25, on hold due to the need for billing system upgrades, as proposed under PG&E’s BMI.
Table 1
PG&E’s Rate Projects On Hold Due to The Need for Billing System Upgrades Rate Implementation
Project
Planned
Completion
Year
Target Delivery Date / Reference
Residential Net Billing for Paired
Storage, SmartMeter Opt-out
and MV-90 customers in ABS
2025 (in BCS) Target delivery date: 12/31/25
CPUC Executive Director Approval of
Request for Additional Time to Comply under
Rule 16.6 dated 4/8/2024.
E-ELEC Standard NEM 1.0, 2.0
and Paired Storage customers in
ABS
2025 (in BCS) Target delivery date: 01/2026
CPUC Executive Director Approval of
Request for Additional Time to Comply under
Rule 16.6 dated 9/19/2024.
BillingModernization_DR_PCE_001-Q013 Page 2
Non-Residential Net Billing
Simple NEM, Paired Storage,
and Medical Discount
2026 (in BCS
and CC&B)
Target delivery date: 03/31/26
CPUC Executive Director Approval of
Request for Additional Time to Comply under
Rule 16.6 dated 6/20/2024.
E-ELEC Complex NEM 1.0 and
2.0 for Virtual NEM, NEM
Aggregation and NEM Multi-Tariff in ABS
2027 (in BCS) Target delivery date: 09/2027
CPUC Executive Director Approval of
Request for Additional Time to Comply under
Rule 16.6 dated 9/19/2024.
Net Billing for Complex NEM
Aggregation and Virtual NEM
2027 (in BCS) Target delivery date: 06/30/25
D. 23-11-068, OP 12 D. PG&E plans to file a
Rule 16.6 request to extend implementation
to 11/30/2027.
New Agricultural Rates (AG-A3
and AG-B2)
2027 (in BCS) No specific compliance timing (as soon as practicable)
D.21-11-016, OP 19.
Including a breakout of PCIA on
bundled customers billing
statements
2028 (in BCS
and CC&B)
Target delivery date: 12/31/27 (workaround
currently in place)
CPUC Executive Director Approval of
Request for Additional Time to Comply under
Rule 16.6 dated 4/26/23
B-20R Solar Rate 2028 (in BCS) No specific compliance timing (as soon as practicable)
D.21-11-016, p. 152.
Commercial Electric Vehicle
Opt-in RTP rate
Not Yet
Planned -
Current
Compliance
2/28/25
Target delivery date: 02/28/26
CPUC Executive Director Approval of
Request for Additional Time to Comply under
Rule 16.6 dated 2/20/25. Petition for
Modification to remove this requirement is
under consideration by the CPUC.
Commercial Electric Vehicle
Non-NEM Export Rate Pilot
Not Yet
Planned -
Current
Compliance
2/28/25
Target delivery date: 02/28/26
CPUC Executive Director Approval of
Request for Additional Time to Comply under
Rule 16.6 dated 2/20/25. Petition for
Modification to remove this requirement is
under consideration by the CPUC.
Modified Cost Allocation
Methodology for Resource
Adequacy for other Load Serving
Entities (CCAs, ESPs)
Not Yet
Planned –
Commitment
2027
No specific compliance requirement. PG&E
indicated plans to implement in 2027.
PG&E’s 2024 ERRA Testimony A.23-05-012
pp. 19-14 to 19-15.
BillingModernization_DR_PCE_001-Q017 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_001-Q017
PG&E File Name: BillingModernization_DR_PCE_001-Q017
Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: April 18, 2025
PG&E Witness(es): Leo Yang – Finance
QUESTION 017
Referring to PG&E’s Prepared Testimony, Chapter 7, p. 7-7, lines 25 to 33 and p. 7-8, lines 1 to 4:
a. Please confirm if CCA customers will be responsible for the costs associated with PG&E’s BMI under the common cost allocation methodology defined in D.23-11-069 or D.24-12-038. If not, please explain.
b. If CCA customers will be responsible for the costs associated with PG&E’s BMI through the common cost methodology set forth in either D.23-11-069 or D.24-12-038, please outline what portion of the costs associated with PG&E’s BMI will be allocated to CCA customers relative to bundled customers. c. If CCA customers will be responsible for the costs associated with PG&E’s BMI through the common cost methodology set forth in either D.23-11-069 or D.24-12-038, please explain how PG&E’s cost recovery for its BMI will flow into bundled and CCA customer rates, including the PCIA vintage(s) that the BMI costs will be assigned to.
ANSWER 017
a. For Electric Distribution, Gas Distribution, Gas Transmission and Storage, and Gas Local Transmission, the common cost allocation methodology defined in D.23-11- 069 is the only applicable allocation methodology that will apply and the authorized base revenue requirements for these cost categories are not subject to distinguishing between bundled and CCA customers. PG&E serves all retail load responsible for these charges. Electric Generation is the only revenue adjustment category subject to the common cost allocation methodology of D.23-11-069 that distinguishes between bundled and CCA customers, and other types of departing load. The BMI costs allocated to Electric Generation revenue adjustment mechanisms governed by D.23-11-069 are further broken out based on the common cost allocation approved in D.24-12-038, which allocates costs between Energy Resource Recovery Account (ERRA), Portfolio Allocation Balancing Account BillingModernization_DR_PCE_001-Q017 Page 2
(PABA), and New System Generation Balancing Account (NSGBA) based on where the GRC authorized base revenue requirement for utility-owned generation is recorded. Thus, CCA customers will share the costs allocated to PABA and NSGBA, along with non-exempt direct access customers and bundled customers. b. PG&E only addresses the Electric Generation revenue adjustment category in this response. PG&E’s workpapers for Chapter 7 provide the details of the allocation to Electric Generation, based on the D.23-11-069 common cost allocation methodology, an excerpt of which is shown below. Electric Generation allocation percentages are shown on line 12 and range between 21.4% in 2023 dropping to
8.7% between 2028 – 2030.
As noted above, these amounts are then further broken out based on the common cost allocation approved in D.24-12-038, which allocates costs between ERRA, PABA, and NSGBA. Allocation percentages that applied in 2025 under the D.24- 12-038 methodology are shown in the table below. The allocation percentages are subject to updates as the underlying authorized revenue requirement for utility-owned generation costs are updated.
For costs allocated to PABA, in 2025, the bundled load share was approximately 37 percent and the non-exempt departing load that pays the PCIA is approximately 63 percent. The departing load consists of both CCA load and non-exempt Direct Access load and breaks out as 53 percent CCA load and approximately 10 percent non-exempt DA load. For costs allocated to NSGBA the percentage of CCA load is approximately 49 percent based on PG&E’s 2025 ERRA Forecast billing determinants.
BillingModernization_DR_PCE_001-Q017 Page 3
c. PG&E’s response only addresses the Electric Generation revenue adjustment category given this revenue component does distinguish between bundled and other types of departing load, like CCA. The BMI costs will flow into the identified rate components just as any other cost does – a forecast or authorized amount will be included in the total revenue requirement to be recovered in rates. For Electric Generation revenue adjustment mechanism, those rates are set in the Annual ERRA Forecast proceeding. To estimate what those costs would be, the costs presented in the table above for Electric Generation (line 5) can be allocated between the three revenue adjustment mechanisms (ERRA, PABA, and NSGBA) identified for Electric Generation by applying the percentages used in 2025 for the common cost allocation methodology approved in D.24-12-038. The percentages identified for 2025 are subject to change but for illustrative purposes, these can be used to estimate what the incremental revenue requirement would be. PCE can derive its own estimate of those costs based on the data above, which will be subject to change as the allocation factors and other estimates or variables are updated.
BillingModernization_DR_PCE_001-Q019 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_001-Q019
PG&E File Name: BillingModernization_DR_PCE_001-Q019
Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: April 18, 2025
PG&E Witness(es): Matt Hedges – Information Technology
QUESTION 019
Referring to PG&E’s Prepared Testimony, Chapter 1, p. 1-6, Figure 1-2, and Chapter 6 generally:
a. Did PG&E consider a scenario in which it proceeded immediately with the Stage 3 C2M Implementation (foregoing Stage 1 and Stage 2 of the currently contemplated BMI process)? As part of PG&E’s response, please confirm whether PG&E conducted a cost-benefit analysis of such a scenario, and if so, please provide that analysis. If not, why not?
b. If PG&E proceeded immediately with Stage 3 now and un-paused any currently paused work on Stage 3, when could PG&E expect to deploy C2M to customers? c. If PG&E had never paused its work on Stage 3 C2M implementation, when could PG&E expect to deploy C2M to customers?
ANSWER 019
a. No. PG&E’s plan was always to replace ABS with BCS and move CC&B to C2M.
Please refer to chapter 5 for a detailed explanation of the challenges faced with that approach.
b. PG&E does not have the analysis for the present-day scenario. c. Prior to pausing the C2M project, the anticipated deployment date was in Q4 2026.
BillingModernization_DR_PCE_001-Q020 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_001-Q020
PG&E File Name: BillingModernization_DR_PCE_001-Q020
Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: April 23, 2025
PG&E Witness(es): Kellie Reem – Information Technology
QUESTION 020
Referring to PG&E’s Prepared Testimony, Chapter 2, p. 2-15, lines 8-12:
a. Please identify the originally anticipated end of life dates associated with PG&E’s legacy billing systems and the year(s) in which those systems became fully depreciated.
b. At what point in these assets’ expected service life did PG&E begin to analyze the most cost-effective way to replace these assets? Please explain PG&E’s rationale behind undertaking these analyses at that point in time (as opposed to previously). c. Generally, what is PG&E’s view of the optimal timeline for analyzing IT asset replacement options relative to the lifespan of the current aging system? d. Generally, what is PG&E’s view of the optimal timeline for undertaking a replacement of its IT assets relative to the lifespan of the current aging system? ANSWER 020
a. PG&E assumes that the legacy systems refers to the Advanced Billing System and the CC&B version currently used today. PG&E’s Chapter 2 section B, p.2-9 describes the Billing systems’ history. See Chapter 2, section B, p.2-15 which describes the years the legacy billing systems were put into service as well as the years they became depreciated.
b. PG&E began to analyze the most cost-effective way to replace these assets in 2018. Refer to Accenture case study WP 4-2.
c. Generally, PG&E’s optimal timeline for analyzing IT asset replacement options is typically after the asset has been deployed and is operating without significant defects. As a routine part of asset and system maintenance, PG&E periodically conducts asset and system inspections to validate if there are any performance issues or vendor defects that could lead to asset replacement.
BillingModernization_DR_PCE_001-Q020 Page 2
d. Generally, PG&E’s optimal timeline for undertaking a replacement is within the operational lifespan of the asset. For most software and hardware, this is typically between 3 to 10 years. However, in cases where routine maintenance inspections prove replacement is warranted, PG&E will escalate these asset replacements ahead of schedule and within operational budget constraints.
BillingModernization_DR_PCE_001-Q022 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_001-Q022
PG&E File Name: BillingModernization_DR_PCE_001-Q022
Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: April 18, 2025
PG&E Witness(es): Matt Briel – Customer and Enterprise Solutions QUESTION 022
Referring to PG&E’s Prepared Testimony, Chapter 3, p. 3-1, lines 13 to 30, and Chapter 4, p. 4-13, lines 9 to 27, and p. 4-22, lines 25 to 30:
a. In its 2018 evaluation, what did Accenture ultimately recommend PG&E do (as a target state solution) to address the risks it identified, and on what timeline? b. In its 2022 evaluation, what did Accenture recommend PG&E do (as a target state solution) to address the risks it identified, and on what timeline? c. If PG&E’s current BMI proposal is on a different timeline than those identified in PG&E’s responses to part (a) and/or (b), please explain why.
ANSWER 022
a. As a target state solution the recommendation from Accenture, in 2018, was to re-platform to a next generation CIS within the 2024 timeframe. Accenture states, “In this scenario, PG&E would select a fully integrated CIS technology suite from one of the market leaders in the industry – Oracle or SAP.”
b. The 2022 evaluation from Accenture acknowledges phase 1: BCS – ABS Electric Replacement was already underway and “PG&E should build on its momentum to re-platform its meter to cash solution.” The only mention of timeframe was to note the BCS – ABS Electric Replacement phase had a target completion date of 2023. c. PG&E provided context for why the original BCS – ABS Electric Replacement target completion date was not met in PG&E’s Prepared Testimony, Chapter 5, p. 5-10 line 26 through p. 5-22 line 18.
BillingModernization_DR_PCE_001-Q026 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_001-Q026
PG&E File Name: BillingModernization_DR_PCE_001-Q026
Request Date: April 4, 2025
Requester DR No.: 001
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: April 18, 2025
PG&E Witness(es): Matt Hedges – Information Technology
QUESTION 026
Referring to PG&E’s Prepared Testimony, Chapter 5, p. 5-52, line 25 to p.5-53, line 20:
please explain how this forecasted stranded cost analysis would change if PG&E transitioned directly from the legacy systems to the C2M? ANSWER 026
There would be no stranded costs if PG&E transitions directly from the legacy systems to C2M and the BCS or CC&B 25.1 projects were not implemented.
As described in Chapter 5, page 5-52, lines 25-28 and Chapter 2, section B, the original capital legacy billing system and related capital upgrades have been fully depreciated.
There are no stranded costs associated with the legacy billing systems (CC&B, ABS, and MDMS). Thus, there would be no stranded costs if the BCS or CC&B 25.1 projects were not implemented, since the stranded costs included in testimony are related to those projects.
BillingModernization_DR_PCE_002-Q003 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_002-Q003
PG&E File Name: BillingModernization_DR_PCE_002-Q003
Request Date: May 20, 2025
Requester DR No.: 002
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: June 2, 2025
PG&E Witness(es): Kellie Reem – Information Technology
SUBJECT: SECOND DATA REQUEST OF PCE
QUESTION 003
Referring to PG&E’s Prepared Testimony, Chapter 4, p. 4-28, lines 4 to 10:
a. Please provide a timeline for when PG&E implemented CC&B 2.4. b. Please explain if there were any CC&B version releases between the releases of CC&B 2.4 and CC&B 25.1, documenting each version’s release date. c. Please provide timelines for the implementation of any CC&B version releases completed by PG&E between the releases of CC&B 2.4 and CC&B 25.1.
ANSWER 003
a. In 2017, PG&E upgraded CC&B from version 2.3 to version 2.4, which is the version currently in use.
b. Oracle has released 6 updated versions of the software since 2.4. CC&B Release Dates are follows:
CC&B 2.4 October 2013
CC&B 2.5 October 2015
CC&B 2.6 May 2017
CC&B 2.7 August 2018
CC&B 2.8 April 2021
CC&B 2.9 April 2022
CC&B 25.4 April 2025
BillingModernization_DR_PCE_002-Q003 Page 2
c. PG&E has not upgraded CC&B since 2017 to a newer version since 2017.
BillingModernization_DR_PCE_002-Q009 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_002-Q009
PG&E File Name: BillingModernization_DR_PCE_002-Q009
Request Date: May 20, 2025
Requester DR No.: 002
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: June 3, 2025
PG&E Witness(es): Matt Hedges – Information Technology
SUBJECT: SECOND DATA REQUEST OF PCE
QUESTION 009
Referring to PG&E’s response to PCE_001_Q006: Please explain if any of the fees featured on PG&E’s Schedule E-CCA will be impacted by the BMI (or are likely to be impacted by the BMI). If yes, please identify the specific fee and how the fee will be (or is likely to be) impacted.
ANSWER 009
BMI is expected to enhance the efficiency and automation of several processes related to CCA services, as outlined in PG&E’s Electric Schedule E-CCA. As these improvements are implemented over the course of the initiative particularly as the system transitions to its target state in Stage 3, PG&E anticipates that certain activities currently require manual intervention may become more streamlined and system driven.
While it is premature to identify specific changes to fee structures at this time, these services are expected to benefit from automation, improved data handling, and reduced administrative effort under the upgraded system. Any proposed adjustments to these fees would be evaluated upon completion of the relevant BMI phases and submitted for review and approval through the appropriate regulatory processes.
BillingModernization_DR_PCE_002-Q010 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_002-Q010
PG&E File Name: BillingModernization_DR_PCE_002-Q010
Request Date: May 20, 2025
Requester DR No.: 002
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: June 3, 2025
PG&E Witness(es): Matt Hedges – Information Technology
SUBJECT: SECOND DATA REQUEST OF PCE
QUESTION 010
Referring to PG&E’s response to PCE_001_Q006:
a. Please itemize the specific changes or upgrades in PG&E’s BMI process that could potentially “improve efficiency in managing and supporting third-party energy service providers such as Community Choice Aggregators (CCAs).” b. Please provide a list of the billing system efficiency metrics that PG&E currently tracks for either/both its CCA and bundled service customers.
ANSWER 010
a. Billing Modernization Initiative, as described in Chapter 4 of its testimony in the BMI filing is expected to improve operational efficiency in managing and supporting third-party energy service providers including CCAs. The initiative includes a transition to an integrated platform that is intended to modernize PG&E’s customer, billing and metering systems. While the following list outlines potential areas of improvement, it is not a comprehensive or final list, as PG&E is still in the early stages of the BMI program. Many specific features have not yet been finalized, confirmed, or prioritized for implementation, particularly those planned for later phases (Stage 3). Subject to those qualifications, anticipated upgrades include:
• Market Transaction Management (MTM) Module: enables centralized, rule-based processing of enrollment, usage, and billing data exchanges with CCA, replacing decades worth of custom code and integrations
• Integrated Meter and Data management (via MDM and ODM Modules):
streamlines the collection, validation, and transfer of meter data that will improve accuracy and reduce exception handling, benefiting third party ESPs BillingModernization_DR_PCE_002-Q010 Page 2
• Consolidated Billing Capabilities: enhance support for both rate-ready and bill-ready billing models through improved system configuration and more consistent application of third-party rates and charges
• Exception Handling and Validation Tools: introduces near real-time processing logic to identify and resolve data mismatches or incomplete transactions, minimizing delays and manual corrections
b. PG&E tracks a variety of internal billing system efficiency metrics to monitor operational performance across all residential and commercial customer segments.
These metrics are not disaggregated by CCA or bundled service customers, as billing processes are largely shared across customer types. Examples of billing efficiency metrics currently tracked include, but are not limited to:
• Unbilled Revenue: monitors billed revenue that is uncollectible due to timing, system constraints, or limitations defined under Rule 17.1 • Quality Assurance Standard – Late Commencing Bills: tracks bills issued more than 60 days after service start
• Delayed Bills: identifies bills not generated within 35 days of the previous bill date • Customer Initiated Request Open > 45 Days: measures the percentage of service or billing-related request that remain unresolved 45 days after initiation.
These metrics are drawn from various operational reports used to manage billing accuracy, timeliness, and customer responsiveness. Additional metrics maybe also be used internally for system performance and compliance monitoring.
BillingModernization_DR_PCE_002-Q011 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_002-Q011
PG&E File Name: BillingModernization_DR_PCE_002-Q011
Request Date: May 20, 2025
Requester DR No.: 002
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: June 3, 2025
PG&E Witness(es): Matt Hedges – Information Technology
SUBJECT: SECOND DATA REQUEST OF PCE
QUESTION 011
Referring to PG&E’s response to PCE_001_Q006:
a. Please explain how PG&E currently sets these CCA service fees (i.e., PG&E’s methodology for determining the appropriate fee amounts). b. Does PG&E anticipate continuing to use this same methodology referenced in part (a) after the BMI upgrades? If not, please explain any anticipated changes to PG&E’s methodology.
c. Please confirm if PG&E applies and will continue to apply an inflation factor to determine CCA service fees. If confirmed, please explain how this inflation factor is calculated.
d. If part (c) is confirmed, please explain if PG&E expects CCA service fees to increase over time due to the application of an inflation factor. e. Does PG&E anticipate that its implementation of the BMI will, on balance, improve efficiency in supporting CCAs? If not answered in the affirmative, please explain why.
f. All else being equal, would the referenced “streamlined processes” lead to reduced CCA service fees? If not, why not.
g. All else being equal, would the referenced “reduced reliance on manual interventions” lead to reduced CCA service fees? If not, why not. h. All else being equal, would the referenced “consolidated systems” lead to reduced CCA service fees? If not, why not.
i. Please provide examples of the kinds of “regulatory requirements” that might raise CCA service fees in the future. What does PG&E mean by that phrase in this context?
BillingModernization_DR_PCE_002-Q011 Page 2
j. Please provide examples of the kinds of “future operational needs” that might raise CCA service fees in the future. What does PG&E mean by that phrase in this context?
k. Please provide examples of the kinds of “unforeseen system complexities” that might raise CCA service fees in the future. What does PG&E mean by that phrase in this context?
l. Referring also to PG&E’s response to PCE_001_Q007, please explain what PG&E means by “the complexity of cost allocation”, and specifically, how that complexity could raise CCA service fees in the future.
ANSWER 011
a. PG&E’s CCA service fees listed in Electric Schedule E-CCA are developed based on the estimated labor time, materials, system usage, and administrative effort required to perform each service. Fee calculations typically reflect internal cost-of-service estimates, consistent with principles used in other unbundled service fee determinations. Fees are reviewed and approved through applicable regulatory proceedings and are maintained by various operational groups across the company. b. PG&E anticipates continuing to use a similar cost-based methodology post-BMI.
Once BMI is fully implemented and the new system has stabilized, PG&E may revisit the inputs and assumptions behind the fee calculations to reflect changes in system design, automation, and labor effort associated with performing the underlying services.
c. Yes, in applicable proceedings PG&E has applied an inflation or escalation factors based on expected labor cost growth. This typically reflects enterprise-wide labor escalation rates or other cost forecast factors reviewed in general rate case (GRC) proceedings.
d. Yes, if the inflation factor continues to be applied, PG&E would expect that certain CCA service fees could increase over time, subject to regulatory approval. e. Yes, PG&E anticipates that, once fully implemented, the BMI will improve operational efficiency in supporting CCA-related services. These improvements are expected to stem from increased automation, data standardization, and streamlined workflows. The full benefits of BMI are not expected to be realized until the final stages of BMI.
f. While the BMI is designed to streamline many operational processes, not every process will be streamlined. As PG&E retires decades of custom code and adopts standardized base-product workflows, certain services may experience increased processing time or operational complexity. In some cases, efficiencies in one area may be offset by additional steps or requirements in another. The overall impact is expected to vary across services and may balance out across multiple processes.
Any potential impact on service fees would be assessed through a comprehensive cost review and subject to Commission approval.
g. Reduced manual intervention is expected to improve efficiency and reduce the risk of human error for certain processes. The extent of cost savings will vary depending on service complexity, volume, and system design. Reductions in administrative BillingModernization_DR_PCE_002-Q011 Page 3
effort may not directly translate into lower service fees without a post-implementation cost analysis.
h. Consolidating systems may reduce data duplication, streamline reporting, and lower maintenance burdens. However, initial implementation and transition costs may offset these efficiencies in the near term. Any long-term fee adjustments would depend on operational cost impacts following full deployment and would be subject to Commission review.
i. Regulatory requirements that could increase CCA service fees in the future may include, but are not limited to, new or evolving obligations that introduce additional complexity, system enhancements, or administrative workload. Examples include:
a. Provider of Last Resort (POLR) Implementation: as PG&E steps into new roles related to POLR, including mass transitioning CCA customers back to bundled service in the event of a CCA failure or market exit, new processes are being developed that do not currently exist within legacy systems. b. Data Privacy and Compliance Mandates: regulations such as California Consumer Privacy Act (CCPA) and potential future legislation may require enhancements to data handling processes, consent tracking, customer communication protocols and data reporting. Compliance with these lays may lead to increased system and labor costs associated with managing CCA customer data in a compliant manner.
c. Customer Billing and Notification Enhancements: Commission directives requiring changes to bill presentment (e.g., inclusion of dynamic rate components or standardizing messaging)
These examples reflect that CCA services fees may affect not only by system efficiencies but also by additional complexity introduced by emerging regulatory frameworks.
j. “Future operational needs” refer to changes in business practices, staffing, systems, or support processes that may arise to maintain or improve service delivery that could impact CCA service fees.
k. “Unforeseen system complexities” refer to technical or integration challenges that are not identified until after system implementation that may increase service costs l. “Complexity of cost allocation” refers to the challenge of assigning shared systems or operational costs across various customer groups and services. Example:
determining the appropriate portion of shared IT infrastructure costs attributable to CCA related services.
BillingModernization_DR_PCE_002-Q013 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_002-Q013
PG&E File Name: BillingModernization_DR_PCE_002-Q013
Request Date: May 20, 2025
Requester DR No.: 002
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: June 3, 2025
PG&E Witness(es): Matt Hedges – Information Technology
SUBJECT: SECOND DATA REQUEST OF PCE
QUESTION 013
Referring to PG&E’s response to PCE_001_Q010:
a. Please provide a sample of a current PG&E bill for a bundled electric service residential customer, redacting any Protected Personal Information if needed. b. Please provide a sample of a current PG&E bill for a departed electric service residential customer (CCA customer), redacting any Protected Personal Information if needed.
ANSWER 013
a. See attachment: BillingModernization_DR_PCE_002-Q013Atch01.pdf b. See attachment: BillingModernization_DR_PCE_002-Q013Atch02.pdf
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BillingModernization_DR_PCE_002-Q014 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_002-Q014
PG&E File Name: BillingModernization_DR_PCE_002-Q014
Request Date: May 20, 2025
Requester DR No.: 002
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: June 2, 2025
PG&E Witness(es): Matt Hedges – Information Technology
SUBJECT: SECOND DATA REQUEST OF PCE
QUESTION 014
Referring to PG&E’s response to PCE_001_Q010:
a. What is the general timeline, currently, for PG&E to implement a CCA’s request for an on-bill message change? Please provide any form(s) or document(s) used by PG&E to implement these changes.
b. Please explain if the upgrades associated with PG&E’s BMI are anticipated to reduce the time it takes PG&E to implement a CCA’s request for an on-bill message change. Why or why not?
c. Please explain if PG&E is generally aware of the timelines for other IOUs (e.g., SCE or SDG&E) to complete a CCA’s request for an on-bill message change. d. Referring also to Attachment 1 hereto, is PG&E aware that SCE’s timeline for completing a CCA request for an on-bill message change is two business days? If so, what is PG&E’s understanding of the reason(s) for the discrepancy between PG&E’s and SCE’s processing times?
ANSWER 014
a. PG&E does not utilize a standardized or formalized form for CCA on-bill message change request. Requests are submitted via email directly to PG&E CCA team.
PG&E is in the process of developing a formal request form to standardize and improve the intake and tracking of such requests. The current timeline to implement a CCA on-bill messaging request is typically two to three months, depending on internal review, legal compliance changes and scheduling of IT development work. b. PG&E is currently in the early stages of BMI, and the system capabilities that may support improved message configuration and scheduling are not expected to be available until Stage 3. As such, PG&E does not anticipate immediate changes to the processing timeline until those future-stage functionalities are implemented.
BillingModernization_DR_PCE_002-Q014 Page 2
c. PG&E is aware that other IOUs such as SCE and SD&E may follow different internal processes and timelines for processing on-bill message change requests from CCAs. PG&E understands that timelines can vary based on each utility’s system architecture, resource availability, and messaging policies. d. PG&E is aware that SCE reportedly processes on-bill messaging requests from CCAs within two business days, as referenced in attached (Attachment 1 - SCE Bill Message Request Template.pdf). PG&E understands that the shorter processing time may be due to differences in system architecture, configuration and integrations and processes.
BillingModernization_DR_PCE_002-Q015 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_002-Q015
PG&E File Name: BillingModernization_DR_PCE_002-Q015
Request Date: May 20, 2025
Requester DR No.: 002
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: June 3, 2025
PG&E Witness(es): Matt Hedges – Information Technology
SUBJECT: SECOND DATA REQUEST OF PCE
QUESTION 015
Referring to PG&E’s response to PCE_001_Q010:
a. Please describe and provide an example bill showing the portion(s) of a current CCA customer bill that can include messaging/content from a CCA. b. Does PG&E anticipate redesigning CCA customer bills after implementing (or as part of its implementation of) the upgrades associated with PG&E’s BMI? If not, why not? If unknown, please explain why PG&E is not prioritizing this kind of redesign in its upgrade.
c. At what point in the BMI upgrade process would it be most efficient for PG&E to undertake a bill redesign (if it was ordered to do so by the Commission)? Please explain.
d. Please explain if the upgrades associated with PG&E’s BMI will allow CCA messaging on customer bills to be more specific to customer types. If not, why not? If unknown, please explain why PG&E is not prioritizing this change in its upgrade. e. Please explain if the upgrades associated with PG&E’s BMI will allow CCA messaging on customer bills to be larger in size (i.e., more text allowed). If not, why not? If unknown, please explain why PG&E is not prioritizing this change in its upgrade.
f. Please explain if the upgrades associated with PG&E’s BMI will allow CCA messaging on customer bills to address all customers. If not, why not? If unknown, please explain why PG&E is not prioritizing this change in its upgrade. g. Please explain if the upgrades associated with PG&E’s BMI will allow CCAs to send messages directly to specific customer groups (e.g., residential, commercial, etc.).
If not, why not? If unknown, please explain why PG&E is not prioritizing this change in its upgrade.
BillingModernization_DR_PCE_002-Q015 Page 2
ANSWER 015
a. See attachment: BillingModernization_DR_PCE_002-Q015Atch01.pdf b. PG&E does not currently anticipate a full bill redesign as part of the current scope of the BMI. While system functionality will be enhanced, bill redesign elements such as layout, font, size and formatting would be considered secondary features and have not been prioritized in the initial phases of implementation. c. If directed by the Commission, it would be most efficient for PG&E to undertake a CCA bill redesign after initial go-live, during post-implementation phases of BMI (Stage 3 and beyond). By that point, core functionality will be stabilized, and PG&E will be better positioned to leverage new features, evaluate presentment capabilities, and integrate any redesign with operational regulatory, and rate implementation requirements. Attempting a full redesign during initial deployment may introduce risk to program timelines and increase complexity during system stabilization. d. The current system already supports some level of customer-specific messaging via text inserted in the charge lines (e.g. within the CCA generation section of the bill), where messaging can vary depending on what CCAs submit for each customer. No specific functionality has been confirmed or prioritized at this stage to further segment messages based on customer class (e.g. residential, commercial).
BillingModernization_DR_PCE_002-Q015 Page 3
e. BMI platform may technically offer greater flexibility in the future, however an increase in content length has not yet been defined or prioritized. Text volume and formatting changes are not currently part of the initial implementation scope, as PG&E has prioritized foundational system capabilities and compliance-related functions.
f. The current system allows CCAs to message all customers via the static message area or customer-specific charge line text, depending on the data provided by the CCA. BMI may enhance how this functionality is delivered and managed, but as of now, no specific change has been defined or implemented to expand the addressability of all customers beyond current methods. The ability to improve message reach and formatting may be evaluated in later stages, once implementation is complete and new tools are assessed.
g. At this stage, PG&E has not finalized or prioritized enhancements to allow CCAs to directly target specific customer groups for messaging purposes. Current messaging capability depends on the data provided by the CCA and supported by legacy systems.
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BillingModernization_DR_PCE_002-Q016 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_002-Q016
PG&E File Name: BillingModernization_DR_PCE_002-Q016
Request Date: May 20, 2025
Requester DR No.: 002
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: June 2, 2025
PG&E Witness(es): Matt Hedges – Information Technology
SUBJECT: SECOND DATA REQUEST OF PCE
QUESTION 016
Referring to PG&E’s response to PCE_001_Q010:
a. Please explain if the upgrades associated with PG&E’s BMI will allow for CCAs to include clickable URLs on customer bills. If not, why not? If unknown, please explain why PG&E is not prioritizing this change in its upgrade. b. Please explain if the upgrades associated with PG&E’s BMI will allow CCAs the ability to use logo and color branding on customer bills. If not, why not? If unknown, please explain why PG&E is not prioritizing this change in its upgrade. c. Please explain if the upgrades associated with PG&E’s BMI will allow the bill detail received by solar customers with batteries to be included in the blue and white bill.
If not, why not? If unknown, please explain why PG&E is not prioritizing this change in its upgrade.
ANSWER 016
a. PG&E’s bill output is generated in IBM AFP (Advanced Function Presentation) format, which does not support clickable links. This format is then converted to PDF by one of PG&E’s external vendors, which also does not have the capability to render clickable links in the final bill output. As a result, the inclusion of clickable URLs is not currently supported.
b. CCA specific logo or color branding is not currently part of the initial scope. PG&E produces a standardized bill with PG&E as the billing agent for all customers, including those served by CCAs. Branding changes, including the addition of third-party logos or colors, would require significant design, compliance, and print processing changes. Most bill formatting capabilities reside downstream of the billing system, and changes to support branding would require updates to external rendering systems and design templates. These enhancements are not prioritized in the current phase of BMI.
BillingModernization_DR_PCE_002-Q016 Page 2
c. Detailed billing information for solar customers with battery systems is provided in supplemental formats due to current system constraints. As PG&E progresses through the BMI, it anticipates consolidating bill formats, which may enable the inclusion of this detail within the standard bill layout. This functionality has not yet been finalized or prioritized for early implementation. Full evaluation of formatting changes and expended content integration will occur in future stages of the initiative.
BillingModernization_DR_PCE_002-Q017 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_002-Q017
PG&E File Name: BillingModernization_DR_PCE_002-Q017
Request Date: May 20, 2025
Requester DR No.: 002
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: June 2, 2025
PG&E Witness(es): Matt Hedges – Information Technology
SUBJECT: SECOND DATA REQUEST OF PCE
QUESTION 017
Referring to PG&E’s response to PCE_001_Q010: Please explain how dynamic rates will be presented in customer bills after the completion of PG&E’s BMI. Please explain any differences between bundled and unbundled bills for this item.
ANSWER 017
PG&E is still in the early stages of implementing the initiative. Final bill presentment features, including the display of dynamic rate components, have not yet been designed or finalized, and the most billing presentation changes are not expected to occur until Stage 3, the target state of the initiative, which remains several years away. PGE&E is not able to confirm the final format or level of detail that will be presented on customer bills related to dynamic rates. These decisions will be determined later in the program, based on system capabilities, customer needs, and regulatory guidance.
BillingModernization_DR_PCE_002-Q018 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_002-Q018
PG&E File Name: BillingModernization_DR_PCE_002-Q018
Request Date: May 20, 2025
Requester DR No.: 002
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: June 3, 2025
PG&E Witness(es): Matt Hedges – Information Technology
SUBJECT: SECOND DATA REQUEST OF PCE
QUESTION 018
Referring to PG&E’s response to PCE_001_Q011:
a. Please provide a sample of a current PG&E bill for (i) a CARE bundled electric service residential customer, redacting any Protected Personal Information if needed, and (ii) a CARE unbundled electric service residential customer, redacting any Protected Personal Information if needed.
b. Please provide a sample of a current PG&E bill for (i) a FERA bundled electric service residential customer, redacting any Protected Personal Information if needed, and (ii) a FERA unbundled electric service residential customer, redacting any Protected Personal Information if needed.
c. To the extent there are differences in the presentation of the CARE and/or FERA discounts on bundled versus unbundled bills, please explain why.
ANSWER 018
a. CARE Bundled: BillingModernization_DR_PCE_002-Q018Atch01.pdf CARE Unbundled: BillingModernization_DR_PCE_002-Q018Atch02.pdf b. FERA Bundled: BillingModernization_DR_PCE_002-Q018Atch03.pdf FERA Unbundled: BillingModernization_DR_PCE_002-Q018Atch04.pdf c. Overall CARE and FERA discount is shown on PG&E page of the bill, so there are no differences in presentation.
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BillingModernization_DR_PCE_002-Q028 Page 1
PACIFIC GAS AND ELECTRIC COMPANY
Billing Modernization
Application 24-10-014
Data Response
PG&E Data Request No.: PCE_002-Q028
PG&E File Name: BillingModernization_DR_PCE_002-Q028
Request Date: May 20, 2025
Requester DR No.: 002
Requesting Party: Peninsula Clean Energy
Requester: Julia Kantor
Date Sent: June 2, 2025
PG&E Witness(es): Leo Yang - Finance
Matt Briel – Customer and Enterprise Solutions
SUBJECT: SECOND DATA REQUEST OF PCE
QUESTION 028
Referring to PG&E’s response to PCE_001_Q017:
a. Please confirm if PG&E believes that the potential benefits of the BMI upgrades will be the same for all CCAs. If not, please explain why not. b. Please explain why, under PG&E’s proposed cost allocation, there are specific PCIA vintages responsible for BMI costs, even though the BMI will theoretically benefit all bundled and unbundled customers.
ANSWER 028
a. Yes, benefits are accrued to all retail customers, which include Bundled, CCA, Direct Access customers.
b. PG&E used the common cost allocation methodology recently approved in PG&E’s 2025 ERRA Forecast Decision, D.24-12-038, for allocation of Electric Supply Administration (ESA) costs. The basis for the ESA allocation is described in Compliance Advice Letter 7488-E, filed January 17, 2025, as:
• ESA Cost shall be allocated to the PABA, ERRA and NSGBA based on the account and vintage assignment for the utility owned generation revenue requirement approved in PG&E’s most recent General Rate Case.
A helpful insight into determining the fairness of the PABA vintage allocation methodology is to understand that ALL bundled and non-exempt departing load customers pay for costs allocated to the Legacy utility-owned generation (UOG) vintage and 2009 vintage PABA subaccount. Those two vintage subaccounts account for 84.4 percent of all allocated generation-related billing modernization costs.
BillingModernization_DR_PCE_002-Q028 Page 2
For the remaining 4.8 percent of costs allocated to Vintage 2010 – 2012 PABA subaccounts, ALL bundled and most non-exempt departing load customers pay for the costs in the vintage subaccounts between 2010 and 2012.
There are limited exemptions for the Vintage 2010 PABA subaccount, i.e., 2009 vintage customers will not be obligated to pay for costs allocated to this subaccount.
Similarly, there are limited exemptions for the 2011 PABA subaccount, i.e., 2009 and 2010 vintage customers will not be obligated to pay for costs allocated to this subaccount.
Bottom line, the PABA allocation factors broadly allocate the costs to all customers responsible for PABA costs, which include bundled and non-exempt departing load customers.
Attachment KJC-3
SCE Bill Message Request Template
RSO Compliance – Internal Use Only Revised March 2023
BILL MESSAGE REQUEST TEM PLATE
It is the client’s responsibility to verify that the bill message content is accurate, the target audience is appropriate, and that all appropriate stakeholders have reviewed and approved (e.g., Management, Law, Regulatory, etc. as applicable). RSO Compliance may request validation of these stakeholder approvals prior to implementation. RSO Compliance is not responsible for the development of any content (FAQs, Fact Sheets, links to SCE.com, etc.) related to the bill message. Please contact RSO Compliance with questions on any section of this template prior to submittal.
NOTE – This completed form must be sent to RSO Compliance at least 2 full business days (48 hours) prior to the start of the bill message. This will allow RSO Compliance sufficient time to review the form and program bill messages in the sytem.
SECTION 1: BILL MESSAGE OVERVIEW
Title of Bill Message: Requester:
Date: Was message used
previously?
Message Request #:
(to be completed by RSO
Compliance)
SECTION 2: BILL MESSAGE DETAIL
Bill Message Title and
Body:
(typically, no more than five
lines)
Describe Purpose of
Message:
Date Message is to begin
appearring on the Bill:
Duration:
(for how long?)
Priority Level:
(legal, regulatory, or emergency
messages are high priority)
Target Audience:
(Specific to rate class)
Account
Level:
SECTION 3: STAKEHOLDER APPROVALS (Client to obtain approvals) Department: Name & Title: Date:
Department: Name & Title: Date:
Department: Name & Title: Date:
Department: Name & Title: Date:
RSO Compliance – Internal Use Only Revised March 2023
SECTION 4: To be completed by RSO Compliance
Facilitator: Date Submitted to SAP:
After Message Implementation
Production Verified by: Production Verification
Date:
Notification to client made by: Notification to Client Date: