Application: 19-11-019 (U 39 M) Exhibit No.: (PG&E-3) Date: July 16, 2020 Witness(es): Various

PACIFIC GAS AND ELECTRIC COMPANY

2020 GENERAL RATE CASE PHASE II

EXHIBIT (PG&E-3)

REVENUE ALLOCATION AND RATE DESIGN

JULY 2020 ERRATA

(REDLINE VERSION)

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PACIFIC GAS AND ELECTRIC COMPANY 2020 GENERAL RATE CASE PHASE II

EXHIBIT (PG&E-3) REVENUE ALLOCATION AND RATE DESIGN

ERRATA TESTIMONY

TABLE OF CONTENTS

Chapter Title Witness

1 REVENUE ALLOCATION AND RATE DESIGN INTRODUCTION

Daniel R. Pease

2 REVENUE ALLOCATION Tysen Streib

Attachment A RATE DESIGN GUIDELINES TO IMPLEMENT REVENUE REQUIREMENT CHANGES

Tysen Streib

3 RESIDENTIAL RATE DESIGN Keith B. Coyne

Jan Grygier Dennis M. Keane Andrew Klingler Kenneth E. Niemi Annette Taylor

Attachment A FEASIBILITY OF REMOTE DISPATCH OF

RESIDENTIAL ENERGY STORAGE Jan Grygier

Attachment B PRESENT AND ILLUSTRATIVE RESIDENTIAL

RATE DESIGNS Dennis M. Keane

4 COMMERCIAL AND INDUSTRIAL RATE DESIGN Daniel R. Pease

Attachment A DETAILED GUIDELINES FOR CHANGING RATES FOR REVENUE CHANGES

Daniel R. Pease

Attachment B COMMERCIAL AND INDUSTRIAL PRESENT AND

PROPOSED RATES Daniel R. Pease

5 AGRICULTURAL RATE DESIGN Keith B. Coyne

Attachment A PRESENT AND PROPOSED AGRICULTURAL RATES

Keith B. Coyne

6 STREETLIGHTING RATE DESIGN Paulina Pra 7 THE ECONOMIC DEVELOPMENT RATE David Gutierrez

(PG&E-3) PACIFIC GAS AND ELECTRIC COMPANY

2020 GENERAL RATE CASE PHASE II EXHIBIT (PG&E-3)

REVENUE ALLOCATION AND RATE DESIGN ERRATA TESTIMONY

TABLE OF CONTENTS

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Chapter Title Witness 8 FEES FOR SERVICES TO COMMUNITY CHOICE

AGGREGATION AND DIRECT ACCESS ELECTRIC SERVICE PROVIDERS

Mathew Workman

Attachment A FEES FOR SERVICES TO CCA AND DA

ELECTRIC SERVICE PROVIDERS Mathew Workman

Attachment B RECOMMENDED REVISIONS TO ELECTRIC

SCHEDULE E-CCA – SERVICES TO COMMUNITY CHOICE AGGREGATORS

Mathew Workman

Attachment C RECOMMENDED REVISIONS TO ELECTRIC

SCHEDULE E-ESP – SERVICES TO ELECTRIC SERVICE PROVIDERS

Mathew Workman

Attachment D ELECTRIC SCHEDULE E-ESPNDSF – ELECTRIC

SERVICE PROVIDER NON-DISCRETIONARY SERVICE FEES

Mathew Workman

9 ELECTRIC ESSENTIAL USE STUDY FOR

RESIDENTIAL CUSTOMERS Brian A. Smith

Attachment A FINAL JOINT INVESTOR-OWNED UTILITIES’

PROPOSAL FOR STUDY TO IDENTIFY ELECTRIC ESSENTIAL USAGE FOR RESIDENTIAL CUSTOMERS

Brian A. Smith

Attachment A1 ESSENTIAL ENERGY PUBLIC WORKSHOP

NOTES Brian A. Smith

Attachment A2 RASS SURVEY INSTRUMENT Brian A. Smith

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PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 1

REVENUE ALLOCATION AND RATE DESIGN INTRODUCTION

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PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 1

REVENUE ALLOCATION AND RATE DESIGN INTRODUCTION

TABLE OF CONTENTS

A. Introduction ............................................................................................................ 1-1

B. Rate Design Objectives ........................................................................................ 1-2

1. Cost of Service ............................................................................................... 1-2

2. Rate Stability ................................................................................................... 1-4

3. Understandable and Provide Meaningful Options ........................................ 1-6

C. Revenue Allocation ............................................................................................... 1-7

1. Generation Revenue Allocation ..................................................................... 1-7

2. Distribution Revenue Allocation ..................................................................... 1-9

3. Public Purpose Program Revenue Allocation ............................................... 1-9

a. CARE Surcharge ................................................................................... 1-10

b. Non-CARE Components Approved for Recovery as PPP .................. 1-10

c. Non-CARE Components Proposed for Recovery as PPP .................. 1-11

4. Revenue Allocation Results ......................................................................... 1-12

D. Rate Design ......................................................................................................... 1-13

1. Distribution Customer Charge ..................................................................... 1-13

2. Distribution Demand and Energy Charges ................................................. 1-14

3. Generation Demand and Energy Charges.................................................. 1-14

4. Total Rate Calculation .................................................................................. 1-14

5. Peak Day Pricing .......................................................................................... 1-15

6. Additional Rate Design Proposals ............................................................... 1-16

E. Organization of the Exhibit.................................................................................. 1-16

F. Conclusion ........................................................................................................... 1-17

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PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 1 2

REVENUE ALLOCATION AND RATE DESIGN INTRODUCTION 3

A. Introduction 4

The second phase of Pacific Gas and Electric Company’s (PG&E) Test Year 5

General Rate Case (GRC) Phase II is the California Public Utilities 6

Commission’s (CPUC or Commission) opportunity to update electric marginal 7

costs and revise the associated revenue allocation and rate design for each 8

customer class. The Commission’s decision in this proceeding will set marginal 9

cost, revenue allocation, and rate design policies for the next three years, 10

including the rate design that will ultimately be applied to PG&E’s authorized 11

revenue requirements, which are determined in other proceedings. 12

Rate design in Phase II proceedings can be generally described to include 13

marginal cost of service studies, revenue allocation and rate design.1 PG&E’s 14

marginal cost of service studies are used to support revenue allocation and rate 15

design presented in this exhibit. Revenue allocation is the step in the rate 16

design process through which individual revenue requirement functions 17

(e.g., distribution or generation) are assigned (or allocated) to each rate group or 18

customer class. Revenue allocation results provide the target levels of revenue 19

based on the fully allocated cost of service. PG&E’s proposals for revenue 20

allocation adjust revenue for each customer group to better reflect the 21

fully-allocated cost of service results. 22

The next step in the rate design process is to derive the prices, or rates, that 23

will apply to each rate schedule based on the allocated revenue. PG&E’s 24

proposals in this proceeding retain the already authorized Time-of-Use (TOU) 25

periods and seek to minimize rate design changes, such as changes to TOU 26

differentials and customer charge levels, to provide a period of stability in rates 27

as discussed further below. 28

PG&E’s proposals in this exhibit are based on May 1, 2020 rates and 29

adopted 2020 test year sales such that the proposed rate changes reflect only 30

the requests in this proceeding. 31

1 See Exhibit (PG&E-2) for PG&E’s cost of service studies.

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In Section B of this chapter, PG&E describes its rate design policy 1

objectives. PG&E’s guidelines for revenue allocation and rate design are 2

described in Sections C and D, respectively, setting the stage for specific 3

revenue allocation and rate design proposals in the chapters that follow. 4

The remainder of this chapter is organized as follows: 5

Section B – Rate Design Objectives 6

Section C – Revenue Allocation 7

Section D – Rate Design 8

Section E – Organization of the Exhibit 9

Section F – Conclusion 10

B. Rate Design Objectives 11

In this proceeding, PG&E seeks to make progress toward rates that are 12

more cost-based, more economically efficient, and promote greater equity 13

among customers, as part of a six-year path forward to fully allocating cost to 14

each customer class. However, efforts to meet these goals must invariably 15

balance multiple competing objectives including: compliance with statutes and 16

CPUC rules, rate stability, understandability, and customer acceptance. PG&E’s 17

revenue allocation and rate design proposals are guided by the following 18

objectives. 19

1. Cost of Service 20

Public Utilities Code Section 451 requires that the Commission establish 21

rates that are “just and reasonable.” Traditionally, “just and reasonable” 22

rates are based on cost of service. The costs of providing utility services 23

vary with customer usage characteristics and with the facilities needed to 24

serve a customer. The Commission has a long history of using Equal 25

Percent of Marginal Cost (EPMC) to establish a cost-based allocation of 26

revenue among customer classes.2 27

In this proceeding, PG&E proposes using the EPMC approach for 28

generation and distribution revenue allocation. Under this approach, each 29

customer class is assigned revenue responsibility for generation and 30

2 See Exhibit (PG&E-2), Chapter 1 for background with regard to the use of marginal cost

for cost of service. PG&E uses the terms “full cost” and “full EPMC” revenue responsibility interchangeably in this exhibit.

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distribution, respectively, in proportion to the marginal cost of generation and 1

distribution service for that class, such that the total revenue for each 2

component is collected. 3

The Commission has consistently held that utilities’ underlying marginal 4

costs should be the basis for revenue allocation and rate design so that 5

customers receive clear and appropriate cost-based price signals 6

associated with their usage characteristics.3 Doing so encourages more 7

efficient use of energy and the delivery system. Further, appropriate price 8

signals help prevent un-economic decision-making by customers. As noted 9

in Decision (D.) 18-08-013 on PG&E’s 2017 GRC Phase II: 10

The advantages of the EPMC approach are its simplicity, transparency 11 and fairness. The equation…is simple and transparent, but it relies on 12 an accurate assignment of marginal costs to each class . It is fair 13 because it assigns the non-marginal costs to each class proportionate to 14 their marginal cost responsibility, which means that those classes that 15 impose the greatest additional (or new) costs on the utility also bear the 16 greatest burden for the existing utility costs. This creates and incentive 17 for every class to avoid imposing additional (or new) costs on the utility, 18 which in theory keeps rates for all classes as low as possible.4 19

The Commission has found “that EPMC-based rate design is: 20

Cost-based; 21

A reasonable balance between equity and efficiency in revenue 22

allocation and ratesetting; and 23

3 In D.15-07-001, addressing residential rate reform, the Commission described 10 rate

design principles. Many support cost-based rate design. For example, (2) Rates should be based on marginal cost. (3) Rates should be based on cost causation principles. (5) Rates should encourage reduction of both coincident and non-coincident peak demand. (7) Rates should generally avoid cross subsidies, unless the cross subsidies appropriately support explicit state policy goals. (9) Rates should encourage economically efficient decision making. (See D.15-07-001, p. 28.)

4 D.18-08-013, pp. 14-15 (emphasis added). That decision also noted that “D.96--04--050 established EPMC as the Commission’s preferred starting point for cost-based rate design and was one of the final Commission decisions to fully litigate marginal costs, revenue allocation, and rate design issues for a major electric utility… . [because o]ur adoption of settlements is not precedential… the findings and conclusions of D.96-04-050 remain valid and should be regarded as the starting point for the Commission’s evaluation of whether revenue allocation and rate designs are reasonable.” (D.18-08-013, p. 19.)

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The Commission’s preferred starting point for evaluating the 1

reasonableness of revenue allocation and rate design.”5 2

The EPMC method makes good policy sense for distribution and generation 3

because it provides a more equitable and economically efficient basis for the 4

allocation of PG&E’s distribution- and generation-related revenue 5

requirements.6 6

As the Commission noted above, it is vital that the assignment of 7

marginal costs to each class be as accurate as possible. Marginal costs 8

have not been fully litigated since PG&E’s 1993 and 1996 GRCs, as the 9

parties have been able to settle most or all issues in Phase II proceedings 10

since then. However, such settlements typically involve caps and floors that 11

have moderated movement of classes to their full cost basis. PG&E here 12

proposes a process for moving all customer classes gradually to their full 13

cost of service over a period of six years, and in this proceeding, asks the 14

CPUC to approve the rate changes necessary to implement the first 15

three years of that transition. PG&E would then reassess cost of service in 16

its 2023 GRC Phase II and propose the continuation of its transition plan in 17

that proceeding. 18

2. Rate Stability 19

While it is important to move toward more appropriate, 20

economically-efficient and cost-based price signals, this goal should be 21

balanced with a concern for mitigating change which may include sudden 22

and unduly large bill increases. Historically, mitigation of change has 23

included a combination of the moderation of the changes made in both 24

revenue allocation and in rate design. As the Commission noted in PG&E’s 25

last GRC Phase II: 26

Of course, other considerations may lead us to find that deviations from 27 EPMC-based and marginal cost-based revenue allocation and rate 28 designs are reasonable….. In the revenue allocation context, ‘caps and 29 floors’ may be used to limit the rate impact of changes to a class’s 30 revenue allocation from one GRC Phase II proceeding to the next. 31 Similarly, in the rate design context, fully cost-based rates may be 32

5 D.18-08-013, pp. 19-20. 6 D.18-08-013, p. 17.

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mitigated in order to ensure that bill impacts between GRC Phase II 1 cycles are not extreme. But an EPMC-based and marginal cost-based 2 revenue allocation and rate design is our favored starting point.7 3

In this proceeding, PG&E moves to adjust revenue allocation, but PG&E 4

specifically acknowledges the substantial changes that customers will be 5

experiencing as a result of already adopted rate initiatives over the next few 6

years. For that reason, PG&E recommends minimizing changes in rate 7

design at this time. 8

In PG&E’s 2018 Rate Design Window (RDW) (D.19-07-004), the 9

Commission has continued the process of reevaluating Residential rates 10

with the goal of moving forward to default Residential customers to TOU 11

rates. The default of Residential customers to PG&E’s new default TOU 12

rate is currently planned to begin in October 2020 and continue in waves for 13

a period of up to eighteen months, ending in 2022. To ensure that changes 14

in rate design do not disrupt this process, PG&E proposes to implement 15

many of its rate design proposals in 2023. 16

In D.18-08-013, the Commission approved new seasonal periods and 17

TOU periods for Non-Residential rates. In addition, in that decision the 18

Commission approved illustrative rates that established the relationships in 19

rates that would be used to implement the rates with new TOU periods. In 20

D.19--05--010, the Commission further considered Agricultural rates and 21

adopted enhancements to the illustrative rates adopted by D.18--08--013 22

that will be used to implement the new Agricultural rates. These new rates 23

were made available to Commercial and Industrial (C&I) customers on a 24

voluntary basis beginning in November 2019 and to Agricultural customers 25

in March 2020. If customers do not opt-in to the new rates with new TOU 26

periods, they will be moved to rates with new TOU periods on a mandatory 27

basis beginning in March 2021.8 28

PG&E currently believes a decision in this proceeding is not likely to be 29

issued before third quarter of 2021 and could be later. Thus, rates with new 30

7 D.18-08-013, p. 20. 8 In Advice Letter 5785-E, PG&E requested to delay the mandatory transfer of C&I

customers to the rates with new TOU periods from November 1, 2020 to March 1, 2021, to align the mandatory dates for C&I and Agricultural customers. PG&E’s request was approved by a letter from the Energy Division Director dated April 20, 2020.

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TOU periods would become mandatory for Non-Residential customers only 1

a short time before a decision is expected in this proceeding. If rates were 2

significantly altered by a decision in this proceeding, the period the rates 3

were available on an opt-in basis would have much less value in informing 4

and educating customers about the final new rates. Such a change could 5

well jeopardize the extensive efforts taken to provide for a smooth transition 6

to the mandatory new TOU periods for Non-Residential customers. 7

Accordingly, PG&E generally requests that the Commission adopt 8

Non-Residential rates in this proceeding that retain substantially the same 9

structure, with similar rate relationships, as authorized by D.18--08--013 and 10

D.19--05--010. 11

3. Understandable and Provide Meaningful Options 12

Along with economically efficient, cost-based pricing, rates should 13

empower customers to take actions to control their energy expenses. 14

Rates should be meaningful in that they allow customers to make choices 15

that permit operational changes that will allow them to reduce their energy 16

expenses. In order to accomplish this objective, rates should be 17

understandable and as simple as possible while retaining appropriate price 18

signals. Rate design proposals should seek to balance the increasing 19

complexity of rates, with the need to provide rates that are understandable 20

and empower customers to take actions to reduce their energy expenses. 21

Rates should also be as transparent as possible. This means 22

unbundled rates (that is, rates unbundled by component such as distribution, 23

Public Purpose Programs (PPP) and generation) should recover costs that 24

are correctly captured within each unbundled component. For example, 25

distribution and generation rates should not be used to recover costs that 26

are associated with providing a public benefit program that might be more 27

appropriately billed with PPP charges. To this end, PG&E recommends in 28

this proceeding that a limited number of programs be reclassified for 29

recovery with PPPs. In addition, in this proceeding PG&E proposes to 30

separately identify the Power Charge Indifference Adjustment (PCIA) as a 31

separate component of bundled generation rates. 32

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C. Revenue Allocation 1

In this proceeding, PG&E is proposing changes in revenue allocation and 2

rate design for generation, distribution and PPP. In addition, the proposed 3

changes to rates affect both the residential Conservation Incentive Adjustment 4

(CIA) rate and the California Alternate Rates for Energy (CARE) surcharge 5

which is a component of the PPP rate.9 PG&E’s proposals for revenue 6

allocation are described in detail in Chapter 2 of this exhibit. 7

PG&E’s objectives for revenue allocation in this proceeding are: (1) to 8

better align cost of service for each customer class through class level revenue 9

allocation; and (2) to achieve greater transparency in rates and charges for 10

policy-related initiatives mandated by both the CPUC and the state of California. 11

As discussed in Exhibit (PG&E-1), even though cost of service has been 12

developed at a more disaggregated level separately recognizing the costs and 13

benefits of Net Energy Metering (NEM) customers, the revenue allocation 14

changes proposed in this proceeding are based on the current customer classes 15

and are fully constrained to ensure that the current rules for NEM rate design are 16

satisfied. This means that rates proposed for NEM customers in this proceeding 17

will continue to be equal to the rates paid by Non-NEM customers. The 18

approach to revenue allocation is summarized in the sections below. 19

1. Generation Revenue Allocation 20

PG&E proposes to allocate generation revenue to bundled customers in 21

two pieces. First, PCIA revenue for each bundled customer group is 22

determined based on the current PCIA for bundled customers (that is, 23

bundled customers are subject to the current PCIA vintage and PCIA rates). 24

Second, the remaining generation revenue is allocated to bundled 25

9 Total rates consist of a number of different functions including: distribution;

transmission; generation; Nuclear Decommissioning; PPP; Competition Transition Charges; the New System Generation Charge (NSGC); Energy Cost Recovery Amount; Department of Water Resources Bond; and greenhouse gas allowance volumetric and by semiannual credits. In addition, Direct Access (DA) and Community Choice Aggregation (CCA) customers pay the PCIA and the Franchise Fee Surcharge. Transmission charges are regulated by the Federal Energy Regulatory Commission and are not subject to change in this proceeding. PG&E’s proposals for change in this proceeding are limited to rates for PPP, generation and distribution.

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customers based on generation marginal costs described in more detail in 1

Exhibit (PG&E-2). 2

In the past, the PCIA was identified separately only for DA and CCA 3

customers. Even though these same costs had been recovered in bundled 4

generation rates, the PCIA for bundled customers had not been identified 5

separately. In order to support the goals of transparency and equity of cost 6

allocation among bundled, DA and CCA customers, PG&E proposes to 7

allocate the PCIA separately to bundled customers.10 In addition, 8

PG&E proposes to separately identify this rate element in each rate 9

schedule, but to continue to combine this item with generation for bundled 10

customer billing. PG&E expects that bill and tariff presentation of the PCIA 11

for bundled customers will be developed and approved separately pursuant 12

to D.20-03-019. 11 13

Generation marginal cost at the class level is the sum of marginal costs 14

of generation received from NEM customers, the generation delivered to 15

NEM customers and the generation delivered to non-NEM customers. 16

Marginal generation capacity costs, marginal generation energy costs, and 17

flexible capacity costs are determined in Exhibit (PG&E-2), Chapter 3 on a 18

cents per kilowatt-hour (kWh) basis by TOU period. These marginal costs 19

are then scaled (on a kWh basis) to the sales forecast used in this 20

proceeding (currently 2020 sales) to develop marginal cost revenue. For 21

purposes of determining full cost of service for each customer class 22

generation received from NEM customers is allocated to each customer 23

class at marginal cost, while generation marginal cost associated with 24

10 The Commission made the following comment with regard to changes to bundled bills

to separately display the PCIA: “We agree that bundled customers should be made aware of the fact that all customers are paying their share of the utility’s uneconomic costs.” D.18-10-019, p. 119.

11 Ordering Paragraph (OP) 2 of D.20-03-019 requires PG&E, Southern California Edison Company, and San Diego Gas &Electric Company shall collaborate to submit a joint proposal for bill and tariff changes to show a power charge indifference adjustment line item in their tariffs and bill summary tables on all customer bills. Each utility shall submit a Tier 3 Advice Letter by August 31, 2020, to implement the joint proposal by the last business day of 2021. Energy Division is authorized to hold workshops after the filing of advice letters. The proposals must make a showing that the proposed bill and tariff changes are complete and reasonable.

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deliveries to NEM customers and generation marginal costs associated with 1

deliveries to Non-NEM customers is scaled by EPMC. 2

2. Distribution Revenue Allocation 3

PG&E proposes to allocate distribution revenue based on distribution 4

EPMC reflecting the marginal costs described in more detail in 5

Exhibit (PG&E-2). Distribution marginal cost at the class level is the sum of 6

marginal customer costs for NEM customers, marginal customer costs for 7

Non-NEM customers, marginal distribution capacity costs for energy 8

received from NEM customers, marginal distribution capacity costs for 9

energy delivered to NEM customers and marginal distribution capacity costs 10

for energy delivered to Non-NEM customers. Marginal distribution capacity 11

costs are determined in Exhibit (PG&E-2), Chapter 8 on a cents per kWh 12

(¢/kWh) basis by TOU period (where appropriate). These marginal costs 13

are then scaled (on a kWh basis) to the forecast used in this proceeding 14

(currently 2020 sales) to develop marginal cost revenue. For purposes of 15

determining full cost of service for each customer class, distribution marginal 16

capacity associated with energy received from NEM customers is allocated 17

to each customer class at marginal cost, while marginal distribution capacity 18

marginal costs associated with deliveries to NEM customers and distribution 19

capacity costs associated with deliveries to non-NEM customers is scaled 20

by EPMC. Marginal customer access costs for NEM customers and Non-21

NEM customers developed in Exhibit (PG&E-2), Chapter 9, are then 22

applied to forecast of customers to determine the marginal customer cost 23

revenue which is scaled by EPMC to determine revenue allocated to each 24

customer class. 25

3. Public Purpose Program Revenue Allocation 26

PPP revenue currently includes two primary components: (1) the CARE 27

Surcharge, which funds the cost of the CARE Program and the Food Bank 28

Rate Assistance Program; and (2) the cost of non-CARE programs to be 29

recovered as PPP or Public Benefits charges. In addition, the current PPP 30

also includes the Tree Mortality Non-Bypassable Charge as described 31

below. 32

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a. CARE Surcharge 1

As a result of revenue allocation and rate design changes in this 2

proceeding, PG&E proposes to recalculate the CARE discount and the 3

CARE surcharge component of the PPP rates using the 4

currently-effective method. Specifically, PG&E proposes to retain the 5

method currently used to determine the CARE shortfall revenue 6

requirement and to allocate the total CARE surcharge revenue 7

requirement among non-exempt customers on an equal ¢/kWh basis. 8

PG&E proposes to reset the CARE surcharge rates when implementing 9

this decision and to retain the current practice to reset the CARE 10

surcharge once per year thereafter in the Annual Electric True-Up 11

advice letter. 12

b. Non-CARE Components Approved for Recovery as PPP 13

Except for the specific exceptions listed below, PG&E proposes to 14

allocate the non-CARE components of PPP based on Equal Percent of 15

Total Revenue (EPT, total revenue with generation imputed for DA and 16

CCA customers). As discussed in Chapter 2, this represents a small 17

change from the currently approved allocation of these program costs 18

which have historically included the following program costs: (1) Energy 19

Savings Assistance (ESA, or low income energy efficiency); 20

(2) Procurement Energy Efficiency and Public Goods Charge Energy 21

Efficiency; (3) Electric Program Investment Charge; and (4) a portion of 22

Statewide Marketing, Education and Outreach (ME&O).12 23

The Commission has approved several programs to be included in 24

PPP charges based on the same allocation used for other non-CARE 25

PPP programs. In this proceeding, PG&E proposes the same change in 26

allocation to these programs as it is proposing for the other non-CARE 27

PPP programs based on EPT. These programs include: (1) the 28

measurement and evaluation study for the NEM successor tariff 29

(D.18-09-044, OP 13); (2) San Joaquin Valley Disadvantaged 30

Community (DAC) Pilot Program Costs (D.18-12-015, OP 23); 31

(3) San Joaquin Valley DAC Data Gathering Costs (D.18-08-019, 32

12 D.18-08-013 adopted a common allocation for all these cost components.

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OP 13); (4) DAC Green Tariff , DAC Community Solar Green Tariff 1

and the DAC Single Family Solar Home Program Discount, if 2

inadequate allowance revenue is available (D.18-06-027, OP 8 and 3

OP 14); and (5) Behind the Meter Thermal Storage Program Costs 4

(D.19-06-032, OP 5). 5

In addition, the Commission has approved the Tree Mortality Non 6

Bypassable Charge for inclusion with PPP charges (D.18--12--003, 7

OP 9). In that case, however, the Commission specified the revenue 8

allocation for this program. PG&E proposes to use the Commission 9

authorized approach for this component which is equal to the 12-month 10

coincident peak demand method authorized for NSGC. 11

c. Non-CARE Components Proposed for Recovery as PPP 12

Finally, PG&E requests that two programs currently recovered as 13

distribution charges be recovered as PPP charges. Specifically, PG&E 14

requests that Self-Generation Incentive Program (SGIP) and California 15

Solar Initiative (CSI) Program costs be moved from distribution to 16

PPP.13 SGIP costs are currently recovered in distribution, but the 17

Commission revised the allocation for these costs in D.16--06--055 and 18

D.18--08--013. Accordingly, PG&E proposes to recover these SGIP 19

costs with PPP charges but retain the Commission approved allocation 20

methodology which is based on the benefit received by each customer 21

class. PG&E proposes that CSI costs, which were previously collected 22

in the same manner as other distribution revenue, be collected in the 23

PPP charge based on the standard EPT allocation for non-CARE PPP 24

revenue. 25

Finally, in Phase I of the 2020 GRC, PG&E requested approval of a 26

Hydro Public Benefit Cost Non-Bypassable Charge. In PG&E’s request, 27

PG&E deferred the question of rate design for this component to this 28

GRC Phase II. Accordingly, if the Commission adopts a Hydro Public 29

13 CSI costs include the Single Family Affordable Solar Housing and Multifamily Affordable

Solar Home program costs. In adopting San Diego Gas & Electric Company’s proposal to recover SGIP and CSI in PPP rates, the Commission explained that “This shift supports our rate design principles favoring rates that are based on cost causation principles and making incentives explicit and transparent, is reasonable, and should be adopted.” (D.17-08-030, p. 72.)

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Benefit Cost Non-Bypassable Charge in GRC Phase I, PG&E proposes 1

that the rate be allocated based on the standard EPT allocation for non-2

CARE PPP revenue. However, PG&E notes that as a part of the 3

Settlement Agreement in the 2020 Phase I proceeding, PG&E has 4

withdrawn this proposal. Thus, if the Commission adopts that 5

Settlement, PG&E also withdraws its proposal for allocation of this Non-6

Bypassable Charge in this Phase II proceeding.14 7

4. Revenue Allocation Results 8

Revenue allocation results are provided in Chapter 2 of this exhibit, and 9

are provided in detail in Appendix B of Exhibit (PG&E-4). As mentioned 10

above, in this proceeding PG&E proposes to transition all customer classes 11

to their full cost revenue responsibility over a 6-year period. In order to 12

moderate the change to full cost, generation and distribution rates for each 13

customer class would be adjusted by an equal amount each year toward full 14

cost. These adjustments would be applied in addition to any revenue 15

requirement changes. Non-CARE PPP rates (i.e., those components of the 16

PPP rate excluding the CARE surcharge) would be adjusted to the proposed 17

levels in the first year of the 6-year transition period. PG&E’s trajectory 18

toward implementation of full cost in six years would be adjusted, if 19

necessary, in the 2023 GRC Phase II proceeding. 20

In general, PG&E’s proposed allocation would allow both each customer 21

class and each rate schedule within a customer class to be adjusted to full 22

cost over a six-year period. In certain instances, however, PG&E proposes 23

to mitigate the allocation of costs within a customer class for individual rate 24

schedules or groups of rate schedules to preserve relationships across rate 25

schedules, or to avoid unacceptable bundled bill increases resulting from the 26

intra-class revenue allocation. These exceptions are described as 27

applicable in the following chapters. 28

14 PG&Es proposal for a Hydro Public Benefit Cost Non-Bypassable Charge is offered in

A.18-12-009 in Exhibit (PG&E-5), Chapter 8, p.8-24. For withdrawal of this proposal, see the Settlement Agreement of the 2020 GRC, dated December 20, 2019, pp.16-17.

(PG&E-3)

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D. Rate Design 1

As discussed previously, PG&E is seeking changes to rates for generation, 2

distribution and PPP in this proceeding. Unlike PPP rates which are collected in 3

volumetric charges (per kWh), rates for distribution and generation can be 4

collected on a monthly basis (per customer), on a volumetric basis (per kWh), 5

and on the basis of demand (per kW). In addition, both generation and 6

distribution charges may be time-differentiated. PG&E’s proposed rates are 7

discussed in the following chapters of this exhibit: Chapter 3, “Residential Rate 8

Design”; Chapter 4, “Commercial and Industrial Rate Design”; Chapter 5, 9

“Agricultural Rate Design”; and Chapter 6, “Streetlight Rate Design.” Proposed 10

rates for year 3 are set forth in detail in Appendix C of Exhibit (PG&E--4), 11

“Present and Proposed Rates.” In addition, Exhibit (PG&E-5) includes PG&E’s 12

proposed new residential rate as required by D.20-03-003. 13

In D.18-08-013, the Commission clearly indicated its preference for 14

time-differentiated rates that feature differentials equal to fully-scaled marginal 15

cost, and requested that PG&E prepare a number of rate design illustrations to 16

supplement the record in this proceeding to provide parties and the Commission 17

a full range of rate designs. These illustrations are provided in Appendix G, 18

“Illustrative Rate Designs for Commercial and Industrial Customers,” and 19

Appendix H, “Illustrative Rate Designs for Agricultural Customers,” of 20

Exhibit (PG&E-4). 21

1. Distribution Customer Charge 22

Customer charges are assigned entirely to the distribution rate 23

component of each tariff. PG&E generally advocates that customer charges 24

should be determined based on their full, cost-based levels. These levels 25

are derived by scaling up class-specific customer marginal costs by the 26

EPMC multiplier associated with PG&E’s distribution revenue. In this 27

proceeding, however, PG&E does not propose changes to the current 28

customer charges, or, in the case of Medium and Large C&I customer 29

charges, the mechanisms currently approved for updating them. Where the 30

proposed customer charge does not collect the fully-scaled marginal cost, 31

residual customer-related revenue responsibility will necessarily be assigned 32

to non-time varying demand and/or energy charge components of the 33

distribution rates applicable under each rate schedule. 34

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2. Distribution Demand and Energy Charges 1

As a general principle, PG&E recommends that distribution revenue that 2

is not collected in the customer charge should be collected in demand 3

charges, since customer demands are the primary drivers of distribution 4

capacity costs. Ideally, the time differentiation in distribution rates would be 5

accomplished through a peak period distribution demand charge, or 6

alternatively, through time differentiated energy rates. All remaining revenue 7

would then be assigned to a non-coincident demand charge or non-time 8

differentiated energy rates. In the rate design testimony in the following 9

chapters, PG&E describes its proposals for distribution rate design. 10

3. Generation Demand and Energy Charges 11

PG&E recommends that generation revenue should be collected in time 12

differentiated demand15 and energy charges. As discussed above, PCIA is 13

now allocated to bundled customers separately and should be collected 14

from bundled customers on a non-time differentiated, per kWh basis 15

(i.e., the same way it is collected from DA/CCA customers). PG&E generally 16

recommends that generation capacity costs be used to time differentiate 17

generation rates through either a peak period generation demand charge, or 18

alternatively, through time-differentiated energy rates. All remaining 19

revenue would be assigned to collection through energy rates. In the rate 20

design testimony in the following chapters, PG&E describes its proposals for 21

generation rate design. 22

4. Total Rate Calculation 23

As noted above, in this proceeding, PG&E is proposing changes only 24

to rates for distribution, generation and PPP. Rates for all other functional 25

revenue requirement components remain unchanged in illustrative rates 26

presented for approval in this proceeding. In general, rates for each 27

functional revenue requirement component are added together to determine 28

the total bundled rate. 29

However, total Residential rates that include rate tiers are determined 30

differently. In general, total bundled tiered rates are first determined to 31

collect the total revenue, and then rates are unbundled to each functional 32

15 Generation costs are included in reservation charges pursuant to Schedules S and SB.

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revenue requirement component and the CIA is set residually. Residential 1

rates design proposals are set forth in Chapter 3 of this exhibit, and in 2

Exhibit (PG&E-5). 3

5. Peak Day Pricing 4

D.18-08-013 adopted new TOU periods for C&I customers with a later 5

peak period. Similarly, D.18-08-013, and subsequently D.19--05--010, 6

adopted new TOU periods for Agricultural customers with a later peak 7

period. Those decisions, however, did not adopt Peak Day Pricing (PDP) 8

rates with consistent, later event hours. Instead, D.18-08-013 approved 9

settlements16 that recommended the following steps for the PDP program: 10

Suspend default of eligible customers to PDP for the period prior to the 11

date when rates with new, later TOU periods become mandatory. 12

Continue the existing PDP program on an opt in basis during the period 13

prior to when the rates with new, later TOU periods become mandatory. 14

Ensure PDP is available once the new TOU periods become mandatory: 15

PG&E is required to file a Tier 3 advice letter in 2020 in time to gain 16

Commission approval to establish new PDP rates. That Tier 3 advice 17

letter must include revised pricing and PDP event hours that are the 18

same hours adopted for the residential Smart Rate™ Program. 17 19

Resume default of eligible C&I and Agricultural customers to PDP 20

beginning on March 1, following approval of a Tier 3 advice letter, 21

provided approval occurs by November 1 of the prior year. 22

Accordingly, to ensure that PDP is available to Non-Residential 23

customerson June 26, 2020, PG&E will file a Tier 3 advice letter in 2020 in 24

time to gain Commissionfiled Advice Letter 5861-E to request approval to 25

establish C&I and Agricultural PDP rates with event hours of 5 p.m. to 8 26

16 The Standby and Medium and Large Light and Power Rate Design Settlement

Agreement, the Small Light and Power Rate Design Settlement Agreement and the Agricultural Rate Design Settlement Agreement, approved by D.18-08-013. As noted previously, the date for the mandatory transition of C&I customers to the rates with new TOU periods has been extended to March 1, 2021, to coincide with the mandatory date for Agricultural customers. The revised PDP program would be available to C&I and Agricultural customers at the same time.

17 Subsequently, in D.19-07-004 in the 2018 RDW, the Commission approved revised residential Smart Rate event hours of 5 p.m. to 8 p.m. (D.19-07-004, pp. 64-67, Conclusion of Law 49 to 51, OPs 20 to 21.)

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p.m. such.. In that Advice Letter, PG&E requested approval by November 1, 1

2020, so that the revised PDP program cancould be available by 2

March 2021, in anticipation that customers that are taking service on PDP 3

will be enrolled automatically in the new PDP beginning on that date. In 4

addition to proposing changes to the event hours and pricing in the Tier 3 5

advice letter, PG&E will also requestrequested that customers no longer be 6

defaulted to the PDP program. Instead, the program would be retained on 7

an ‘opt-in’ basis. By addressing this issue in the Tier 3 advice letter, there 8

would be an adequate opportunity to gain approval to end the default 9

process prior to 2021. However, in the event that the Commission has not 10

acted on PG&E’s proposal to end the process to default customers to PDP 11

prior to the 2021 operating season, PG&E is also including that proposal in 12

this proceeding. Specifically, PG&E proposes to make PDP available on an 13

opt-in basis, and to end the process of defaulting eligible customers to PDP. 14

6. Additional Rate Design Proposals 15

In Chapter 7 of this exhibit, PG&E proposes to continue its Economic 16

Development Rate (EDR). PG&E believes the EDR is a valuable tool to 17

retain and attract sales in California and should be continued through this 18

GRC cycle. The proposed program would have the same structure as the 19

current EDR with greater rate reductions for customers in cities and counties 20

with higher unemployment rates. 21

In Chapter 8 of this exhibit, PG&E presents its proposal for revisions to 22

DA/CCA fees. In the last GRC, PG&E revised its rates for DA meter fees, 23

the DA/CCA Meter Data Management Agent fee, and for DA/CCA billing 24

fees. In this proceeding, PG&E focuses it revisions to fees that were not 25

addressed in the last GRC. 26

Finally, in Chapter 9, PG&E presents its proposal for the Essential Use 27

Study Plan as required by D.18-08-013. 28

E. Organization of the Exhibit 29

Exhibit (PG&E-3) has a total of nine chapters. The remainder of this exhibit 30

is organized as follows: 31

Chapter 2 – Describes the revenue allocation methods used for each of 32

PG&E’s functional revenues; 33

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Chapter 3 – Sets forth PG&E’s Residential rate design proposals; 1

Chapter 4 – Sets forth PG&E’s C&I rate design proposals; 2

Chapter 5 – Sets forth PG&E’s Agricultural rate design proposals; 3

Chapter 6 – Sets forth PG&E’s Streetlight class rate design proposals; 4

Chapter 7 – Sets forth PG&E’s proposal for continuing the Economic 5

Development Rate Program; 6

Chapter 8 – Describes PG&E’s proposals for updating fees for DA and CCA 7

customers; and 8

Chapter 9 – Sets forth PG&E’s plan for the Essential Use Study as required 9

by D.18--08--013. 10

The following appendices are also provided in Exhibit (PG&E-4): 11

Appendix A – Recorded Average Number of Customers and Sales; 12

Appendix B – Revenue and Average Rate Summary at Proposed Rates; 13

Appendix C – Present and Proposed Rates; 14

Appendix D – Illustrative Bill Impacts; 15

Appendix E – Summary of Compliance Requirements; 16

Appendix F – Baseline Territory Study; 17

Appendix G – Illustrative Rate Designs for Commercial and Industrial 18

Customers; 19

Appendix H – Illustrative Rate Designs for Agricultural Customers; 20

Appendix I – Dimmable Streetlight Rate Design Proposal; 21

Appendix J – Schedule E-CREDIT Update; 22

Appendix K – NEM and Non-NEM Cost of Service Study; and 23

Appendix L – Statements of Qualifications. 24

Finally, Exhibit (PG&E-5) includes the optional residential rate required by 25

D.20-03-003. 26

F. Conclusion 27

In this chapter, PG&E has discussed the general policy objectives that 28

underlie its proposals, including continuing to make progress towards rates 29

that are economically efficient, cost-based and promote equity among 30

customers, as balanced with other objectives. PG&E has also summarized 31

its revenue allocation proposal and its proposed guidelines for designing rates 32

in this proceeding. PG&E respectfully requests approval of its revenue 33

allocation and rate design proposals as presented in this exhibit. 34

(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 2

REVENUE ALLOCATION

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PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 2

REVENUE ALLOCATION

TABLE OF CONTENTS

A. Introduction ............................................................................................................ 2-1

B. Model Improvements............................................................................................. 2-4

C. Marginal Cost Revenue Calculations and Full Cost Retail Average Rates ....... 2-5

D. Distribution Allocation............................................................................................ 2-7

E. Generation Allocation ............................................................................................ 2-7

F. PPP Allocation ....................................................................................................... 2-8

G. Implementation of Rate Changes ......................................................................... 2-9

H. Conclusion ........................................................................................................... 2-10

(PG&E-3)

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PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 2 2

REVENUE ALLOCATION 3

A. Introduction 4

In this 2020 General Rate Case (GRC) Phase II, Pacific Gas and Electric 5

Company (PG&E) is proposing gradual changes to revenue allocation in order to 6

bring each classes’ revenue responsibility closer to their cost of service. 7

PG&E’s goal is to transition allocations to full cost of service over a period of 8

six years. Specifically, PG&E is proposing that distribution and generation 9

revenues be adjusted 1/6th of the way towards allocations in proportion to 10

marginal cost revenue each year for the next three years. PG&E would then 11

reassess marginal costs in its 2023 GRC Phase II and propose the continuation 12

of its transition plan for the following three years in that proceeding. By 13

implementing a multi-year transition plan with a series of relatively small annual 14

changes, PG&E will be able to move customers closer to cost without a single 15

large “step” in rates and without the sometimes counter-intuitive results created 16

by implementing caps and floors. 17

The lack of established marginal costs has made it difficult for PG&E to 18

move towards cost-based allocations in the past decade. The prior two GRC 19

cases settled with less than 1 percent adjustments for bundled customers. 20

In the 2017 GRC Phase II, PG&E advocated for minimal revenue allocation 21

adjustments because substantial shifts in time-of-use (TOU) periods were 22

already going to be major rate changes facing customers during that rate case 23

cycle. In this case, PG&E is minimizing changes in its rate design, in part to 24

ease movement of customer classes closer to their costs of service. 25

PG&E bases its illustrative revenue allocation on the same general methods 26

proposed in its 2017 GRC Phase II proceeding. In the decision that adopted the 27

settlements filed in that proceeding, Decision (D.) 18-08-013, the California 28

Public Utilities Commission (CPUC or Commission) accepted two approaches 29

for revenue allocation. The first approach provided methodologies to be used 30

for the initial allocation of costs following a decision in that proceeding. 31

Table 2-1 provides a summary of the current and proposed allocation methods 32

for distribution, generation and Public Purpose Program (PPP) functional 33

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revenues to be used upon implementation and in each year of the six-year 1

transition plan to move each customer class to full cost. 2

TABLE 2-1 CURRENT AND PROPOSED ALLOCATION METHODS

Line No.

Functional Revenue Category

Customer Group(a)

Adopted Approach in Last Phase II (Adopted Methods Were Approved

Via Settlement(b)) Proposed in This Phase II

1 Distribution All customers

Equal Percent of Marginal Cost (EPMC), limited through application of caps and floors on Direct Access and Community Choice Aggregation (DA/CCA) customers.

Same as prior GRC, but using gradual, annual changes toward full cost instead of caps and floors.

2 Generation Bundled service customers

EPMC, limited through application of caps and floors on bundled customers.

Same as prior GRC, but using gradual, annual changes to full cost instead of caps and floors.

3 PPPs – California Alternate Rates for Energy (CARE) Surcharge

All customers

All CARE distribution and Conservation Incentive Adjustment (CIA) rate differences will be funded through the CARE surcharge, which will be allocated based on equal-cents-per kilowatt-hour (kWh). Set once per year.

Same as prior GRC.

4 PPPs – Self -Generation Incentive Program (SGIP)

All customers

Allocated in distribution as specified by Resolution (Res.) E-4926.

Move revenue to PPP with the same allocation, resulting in no rate impact.

5 PPPs – Tree Mortality All customers

Not in 2017 GRC Phase II. Allocated by the 12 Coincident Peak method, per D.18-12-003.

6 PPPs – Other Non-CARE Surcharge Revenue

All customers

Decision approved a settlement combining all Non-CARE surcharge programs into a single allocator. After implementation, allocation is based on current revenue share.

Allocated on Equal Percent of Total Revenue (EPT) share with generation imputed for DA/CCA customers, (EPT).

_______________ (a) “All customers” includes eligible Bundled, Direct Access (DA), Community Choice Aggregation (CCA), and

Departing Load (DL) customers. (b) “Settlement” refers to the Marginal Cost/Revenue Allocation Settlement adopted in D.18-08-013.

Table 2-2 provides a summary of the current allocation methods for other 3

functional revenues that PG&E is not proposing to adjust in this proceeding. 4

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2-3

TABLE 2-2 CURRENT ALLOCATION METHODS FOR OTHER FUNCTIONAL REVENUE

Line No.

Functional Revenue Category Customer Group(a) Currently Approved Allocation

1 Department of Water Resources Bond Charges

All customers Equal cents per kWh

2 Competitive Transition Costs All customers Generation revenue with revenue imputed for DA/CCA

3 Nuclear Decommissioning All customers Equal-cents-per kWh 4 Transmission Rates (including the

Transmission Revenue Balancing Account Adjustment (TRBAA), Transmission End-Use Customer Refund Adjustment (T-ECRA) and Transmission Access Charge Balancing Account (TACBA) rate)

All customers 12 coincident peak demands (Transmission and T-ECRA) and equal cents per kWh (TACBA and TRBAA)(b)

5 Reliability Services All customers 12 coincident peak demands 6 Energy Cost Recovery Amount All customers Equal cents per kWh

7 New System Generation Charge All customers 12 coincident peak demands 8 CIA(c) All residential

customers Set residually, reflecting decrements from or increments to schedule rates, to preserve the tiered residential total rate structure pursuant to the constraints set forth D.15-07-001.

9 Power Charge Indifference Adjustment (PCIA)

All eligible DA, CCA and DL customers

Set by vintage in accordance with current methodology used in present rates.

_______________ (a) “All customers” includes eligible Bundled, DA, CCA, and DL customers. (b) Transmission rates are established by the Federal Energy Regulatory Commission and are not

subject to change by the CPUC in this proceeding. (c) PG&E has not changed its approach to CIA design, but CIA rates are affected by changes to

other charges made in this proceeding.

The second approach adopted by D.18-08-013 established the revenue 1

allocation methodologies to be applied for Revenue Requirement changes 2

between GRC Phase II proceedings. In summary, for changes between GRCs, 3

PG&E proposes: (1) to continue to apply the methods set forth in Table 2-1 for 4

PPP charges; (2) to use the approaches described in Table 2-3 for distribution 5

and generation rates; and (3) to continue to apply all the methods set forth in 6

Table 2-2 for other functional revenues. Any distribution and generation revenue 7

adjustments from the transition plan would be added to other Revenue 8

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Requirement changes throughout the plan. These proposed methods will apply 1

unless specifically addressed in the following rate design chapters. 2

TABLE 2-3 ALLOCATION METHODS FOR DISTRIBUTION AND GENERATION FUNCTIONAL REVENUES

BETWEEN PHASE II PROCEEDINGS

Line No.

Functional Revenue Category

Customer Group(a)

Last Adopted Approach in Last Phase II

(Adopted Methods Were Approved Via Settlement(b) Proposed in This Phase II

1 Distribution All customers Equal percentage changes.(c)

Same as prior GRC.

2 Generation Bundled service customers

Equal percentage changes. Same as prior GRC.

_______________ (a) “All customers” includes eligible Bundled, DA, CCA, and DL customers. (b) “Settlement” refers to the Marginal Cost/Revenue Allocation Settlement adopted in D.18-08-013. (c) The CPUC fee will continue to be separately allocated on a $/kWh basis per Res.M-4828.

In this chapter, PG&E describes its proposed approach for determining the 3

initial allocation of costs following a decision in this proceeding. The remainder 4

of this chapter is organized as follows: 5

Section B – Model Improvements 6

Section C – Marginal Cost Revenue Calculations and Full Cost Retail 7

Average Rates 8

Section D – Distribution Allocation 9

Section E – Generation Allocation 10

Section F – Public Purpose Program Allocation 11

Section G – Implementation of Rate Changes 12

Section H – Conclusion 13

B. Model Improvements 14

While the main structure of PG&E’s Revenue Allocation and Rate Design 15

(RARD) model used in the 2017 GRC Phase II has largely been preserved for 16

the 2020 case, there are some substantial additions that allow for more detailed 17

analysis of the cost of service for Net Energy Metering (NEM) and Non-NEM 18

customers. Improvements for the 2020 RARD model include: 19

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Separate marginal cost revenues for the NEM and Non-NEM subgroups of 1

customers; 2

Separate billing determinants for NEM and Non-NEM, including the 3

identification of energy returned to the grid; 4

Separate full-cost average rate calculations for NEM and Non-NEM; 5

Incorporation of generation flexible capacity marginal cost revenues; and 6

Explicit allocation of winter super-off-peak billing determinants and 7

revenues. 8

C. Marginal Cost Revenue Calculations and Full Cost Retail Average Rates 9

Marginal cost revenues for distribution and generation have been developed 10

based on the marginal costs discussed throughout the chapters in Exhibit 11

(PG&E-2). Marginal customer access costs are provided in Chapter 9 of Exhibit 12

(PG&E-2). All other marginal costs are developed on a per-kWh basis, by class 13

and schedule, and separately for NEM and Non-NEM customers (that is, 14

separately for delivered and received energy as applicable), and by TOU period 15

where appropriate. Average marginal costs for generation are developed in 16

Exhibit (PG&E-2), Chapter 3, and average marginal distribution capacity costs 17

are developed in Exhibit (PG&E-2), Chapter 8. 18

In the revenue allocation step, these marginal cost values are then 19

multiplied by the forecasted kWh1 of each schedule to determine each 20

schedules’ marginal cost revenue for NEM and Non-NEM separately. Marginal 21

customer costs are multiplied by forecasted customer months to determine 22

marginal customer cost revenue for NEM and Non-NEM separately. Marginal 23

cost revenue is then summed to develop class and schedule level marginal cost 24

revenue. 25

These marginal cost revenues are used to create EPMC allocation factors 26

just as PG&E would have determined them in prior GRCs. The decision to 27

develop separate marginal cost revenues for NEM and Non-NEM customers 28

does not affect the overall revenue allocation. Had PG&E not developed these 29

NEM-specific costs, the resulting combined costs would have been the weighted 30

average of the two groups, resulting in the same total marginal cost revenue and 31

1 This proposal uses the 2020 forecasted sales as developed in PG&E’s 2020 Energy

Resource Recovery Account (ERRA) application.

(PG&E-3)

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allocations. After the removal of certain non-allocated revenues, described in 1

Sections D and E below, the remaining revenue requirements for distribution 2

and generation are allocated in direct proportion to the marginal cost revenues 3

for each schedule. Table 2A-1 shows a summary of the full-cost average rates 4

that would result from that allocation.2 5

The results of Table 2A-1 differ from the NEM and Non-NEM Cost of Service 6

Study provided in Exhibit (PG&E-1), Chapter 1, and Appendix K of Exhibit 7

(PG&E-4) because Table 2A-1 is limited by the rate design rules currently in 8

place for NEM. Specifically, unlike the NEM and Non-NEM Cost of Service 9

Study in Exhibit (PG&E-1), the rates for NEM and Non-NEM customers must be 10

the same, and NEM customers get full retail credit for on energy returned to the 11

grid.3 The allocations must be applied to each schedule for NEM and Non-NEM 12

combined since the two groups cannot be given individual revenue 13

responsibilities while they continue to have identical rates. While full retail credit 14

is given for transmission and NBC revenues, PG&E continues to apply the 15

EPMC scaling only on energy delivered to the customer and not on received 16

energy, similar to the treatment outlined in Chapter 1 of this Exhibit.4 This is 17

done because it more accurately reflects the benefits of received energy by 18

PG&E5 and can be applied to the combined group without specifically changing 19

NEM rates. While the model produces average rate impacts for NEM and Non-20

NEM separately in the proposed rates files, those results are not indicative of the 21

actual rate impacts that NEM customers would experience as the model 22

assumes all customers are on the new TOU periods even though most NEM 23

customers would still be on the more favorable legacy (i.e., grandfathered) TOU 24

periods. 25

2 A more detailed summary of revenue and average rate is provided in Appendix B of

Exhibit (PG&E-4). 3 While NEM 2.0 customers do not receive retail credit for some NBC ’s, PG&E’s current

NEM population is 95 percent NEM 1.0 and so all customers are modeled as NEM 1.0. 4 The marginal cost revenue for received load is very small (less than 1 percent)

compared to delivered load. PG&E has modeled the impact from applying the EPMC scaling to received load and the overall rate impact is minimal (less than 0.1 percent for most classes).

5 When PG&E received energy from the customer, its costs are not reduced by the EPMC-scaled marginal cost.

(PG&E-3)

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D. Distribution Allocation 1

As discussed above, PG&E proposes to allocate its distribution revenue 2

requirement based on distribution marginal cost revenue. PG&E proposes to 3

mitigate the rate changes that would result from a full-cost allocation by only 4

moving 1/6th of the way to full cost each year for three years instead of applying 5

caps and floors, as has been done in the 2014 and 2017 GRC ’s. In order to 6

achieve this transition, PG&E has developed percentage changes that would be 7

applied to modify present rate distribution revenues (net non-allocated) for each 8

schedule on implementation and the following two years. Schedules that have 9

their rates designed together are grouped so that each schedule’s distribution 10

revenue goes up by the same percentage. This includes E-1/EL-1, 11

A-1/A-6/A-15, each E-19 voltage with its respective voluntary schedule, 12

AG-B/AG-C, and each E-20 voltage with its respective FPP schedule. In 13

addition, even though TC-1 receives its own cost allocation, PG&E proposes to 14

limit the distribution increase on this rate schedule to the class average change 15

since allocating the full cost to this schedule would result in a very large rate 16

increase. These distribution changes are listed in Table 2A-3. 17

PG&E will continue to directly assign to each schedule the estimated CARE 18

Program discounts and certain non-allocated distribution revenues (i.e., Electric 19

Base Interruptible Program discounts, employee discounts, other standby 20

revenue, streetlight facilities charges, and the CPUC fee). PG&E proposes to 21

continue to allocate distribution Family Electric Rate Assistance (FERA) program 22

costs to only the residential class. 23

E. Generation Allocation 24

Similar to section D, above, PG&E proposes to allocate its generation 25

revenue requirement based on generation marginal cost revenue. PG&E 26

proposes to mitigate the rate changes that would result from a full-cost allocation 27

by only moving 1/6th of the way to full cost each year for three years instead of 28

applying caps and floors, as has been done in the 2014 and 2017 GRC’s. In 29

order to achieve this transition, PG&E has developed percentage changes that 30

would be applied to modify present rate generation revenues (net non-allocated) 31

for each schedule on implementation and during the following two years. 32

Schedules that have their rates designed together are grouped so that each 33

schedule’s generation revenue goes up by the same percentage. This includes 34

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2-8

E-1/EL-1, A-1/A-6/A-15, each E-19 voltage with its respective voluntary 1

schedule, and AG-B/AG-C. In addition, generation revenue is transferred from 2

AG-B/C to AG-A in order to equalize the average bundled rate impact between 3

the two groups and help mitigate the increases that would otherwise be 4

assigned to AG-B/C. These generation changes are listed in Table 2A-3. 5

As described in more detail in Chapter 1, PG&E is explicitly treating the 6

above-market (PCIA) portion of generation revenues as a non-allocated revenue 7

and applying it to all bundled customers with a rate equal to the latest vintage of 8

PCIA for each class. 9

F. PPP Allocation 10

PG&E proposes to include four components in PPP rates based on revenue 11

allocation that differs for each. The four components are: (1) the CARE 12

surcharge which funds the cost of the low-income CARE Program; (2) all other 13

existing programs including the Electric Program Investment Charge and Former 14

Energy Efficiency Public Goods Charge, Procurement Energy Efficiency, Energy 15

Savings Assistance, and Statewide Marketing, Education and Outreach;6 (3) the 16

Self Generation Incentive Program (SGIP); and (4) the Tree Mortality Non-17

Bypassable Charge. 18

For the CARE surcharge, PG&E proposes to continue the current method of 19

resetting the CARE shortfall rates once each year. These CARE shortfall rates, 20

equal to the difference between the Non-CARE and CARE distribution and CIA 21

rates ultimately established in this proceeding, are multiplied by forecast CARE 22

sales to determine the cost of the CARE discount, referred to as the CARE 23

shortfall revenue requirement. 24

PG&E proposes to continue to reflect the cost of the CARE distribution and 25

CIA discount in the CARE surcharge component of PPP, allocated on an equal 26

cents per kWh basis to all eligible customers, consistent with the language in 27

6 The Commission has approved recovery of several other items as Non-CARE PPP

charges that are not currently included in rates. PG&E proposes EPT allocation for these as well. As mentioned in Chapter 1, these include: (1) the measurement and evaluation study for NEM, (2) San Joaquin Valley Disadvantaged Community (DAC) Pilot Program Cost, (3) San Joaquin Valley DAC Data Gathering Costs, (4) DAC Green Tariff, DAC Community Solar Green Tariff and the DAC Single Family Solar Home Program Discount, if inadequate allowance revenue is available, and (5) Behind the Meter Thermal Storage Program.

(PG&E-3)

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Public Utilities (Pub. Util.) Code section 327(a)(7), enacted through 1

Senate Bill 695, which established Pub. Util. Code Sections 739.1 and 739.9. 2

The second component is currently allocated to customer groups based on 3

an equal percentage change to the component’s current revenue. PG&E 4

proposes to allocate this in proportion to each schedule’s share of total revenue 5

with generation imputed for DA/CCA customers (EPT). Table 2A-4 compares 6

the present and proposed allocation methods for these components. If 7

approved in GRC Phase I, PG&E would also propose to allocate the Hydro 8

Public Benefit Cost Non-Bypassable Charge based on EPT.7 Additionally, 9

PG&E proposes to reclassify the revenues from two programs mentioned in 10

Chapter 1 from Distribution to PPP: (1) California Solar Incentives which PG&E 11

proposes to allocate according to the EPT method described above, and 12

(2) SGIP, described below. 13

SGIP makes up the third component of PPP rates as it requires a different 14

allocation. The revenues from SGIP will maintain their allocation as proscribed 15

by Res.E-4926, and adopted by D.18-08-013, which will result in no overall class 16

impact. 17

Finally, the fourth item to be included with PPP rates is the Tree Mortality 18

Non-Bypassable Charge. PG&E proposes to continue the authorized allocation 19

for the Tree Mortality Non-Bypassable charge based on the same method used 20

for NSGC (12-month coincident peak). 21

PG&E is not proposing to vary PPP allocations over its six-year transition 22

plan. If approved, PG&E would reclassify the revenues from the programs 23

mentioned above and adjust the Non-CARE allocations fully upon 24

implementation. 25

G. Implementation of Rate Changes 26

The total rate levels PG&E will implement as a result of a final decision 27

in this proceeding will depend on the RARD methods approved in this 28

proceeding, as well as revenue requirements adopted by the CPUC or FERC 29

in other proceedings. Illustrative rates provided in this exhibit are based on 30

revenues collected by current rates (effective May 1, 2020) using forecasted 31

7 Application 18-12-009, PG&E GRC Phase I, Exhibit (PG&E-5), p. 8-24. PG&E has

withdrawn this proposal in the Phase I settlement, but it has not yet been approved.

(PG&E-3)

2-10

2020 billing determinants. As a result, the illustrative revenues do not include 1

any forecast of future revenue requirement changes and are not based on the 2

most recently adopted sales forecasts that will actually be used to set rates upon 3

implementation. 4

In this section, PG&E describes its proposal to implement rates resulting 5

from this proceeding as well as its proposal to implement rates arising from 6

future revenue requirement changes. 7

If PG&E’s proposal is approved, the initial rate change resulting from 8

the decision in this proceeding will be implemented as soon as practicable. 9

Assuming there are revenue requirement and sales forecast changes between, 10

the rate change calculation would be conducted in three steps: (1) create 11

interim rates based on the revenue requirements and sales forecasts used in 12

this proposal; (2) adjust the distribution and generation revenues by the amounts 13

listed in Table 2A-3 and then (3) allocate the revised revenue requirements 14

pursuant to any subsequent rate changes and sales forecasts, using the 15

guidelines set forth below. 16

In general, PG&E proposes to continue the existing practices for rate 17

changes to implement revenue requirement changes as adopted in 18

D.18-08-013. PG&E’s proposed guidelines are set forth in Exhibit (PG&E-3), 19

Chapter 2, Attachment A, and would apply unless specifically addressed in each 20

rate design chapter. In particular, generation and distribution rules for rates 21

changes are discussed in each rate design chapter. 22

Some rate changes, either proposed by PG&E or ultimately approved by the 23

Commission, go beyond a simple change to a rate value and may require either 24

a structural change to PG&E’s billing system and/or an extended period of 25

education for PG&E employees and customers. Such changes will be 26

implemented by PG&E diligently, and as rapidly as possible, consistent with 27

other workflow demands, as well as smooth operations of the systems involved, 28

while also allowing time for adequate customer outreach and education. Timing 29

for certain initiatives, such as changes to baseline quantities, are described 30

in the following chapters. 31

H. Conclusion 32

Table 2A-1, “Revenue and Average Rate Summary at Full Cost Rates,” 33

shows the full cost revenue allocation with current retail rules, absent any caps, 34

(PG&E-3)

2-11

floors, or transition plan. Table 2A-2, “Revenue and Average Rate Summary at 1

Proposed Rates,” shows illustrative revenue results for PG&E’s proposed 2

allocation after the first year of the multi-year transition, as well as the 3

cumulative effect of three years of transition, as described in this chapter. 4

Exhibit (PG&E-4), Appendix B, provides these results in greater detail. PG&E 5

recommends that the Commission adopt its proposed allocation methods and 6

transition plans for the allocation of distribution, generation, and PPP. 7

TABLE 2A-1 REVENUE AND AVERAGE RATE SUMMARY AT FULL COST RATES

Line No.

Revenue at May 1, 2020 Rates ($000)

Revenue at Full Cost

Rates ($000)

Class Average Percent Change

in Revenues

1 Bundled Summary 2

Residential $3,192,895180,

968 $3,146,830159,

993 -1.40.7%

3 Small $836,199195 $921,622909,768

10.28.8%

4 Medium $734,656653 $704,620701,878

-4.15%

5 E-19 $876,341284 $825,801013 -5.89% 6 Streetlights $28,740 $29,006224 0.91.7% 7 Standby $82,651 $77,451227 -6.36% 8 Agriculture $1,165,480156,

635 $1,259,789253,

992 8.14%

9 E-20 T $376,432447 $370,867371,728

-1.53%

10 E-20 P $481,189047 $462,893456,294

-3.85.1%

11 E-20 S $212,534518 $195,335193,250

-89.1%

12 System

$7,987,115966,138

$7,994,214978,368

0.12%

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13 DA/CCA Summary 14

Residential $2,464,942408,

180 $2,326,440301,

885 -5.64.4%

15 Small $881,026861,189

$1,033,786995,184

17.315.6%

16 Medium $812,935787,179

$844,107813,376

3.83%

17 E-19 $1,136,686092,078

$1,098,701050,451

-3.38%

18 Streetlights $27,35426,840 $23,714214 -13.35% 19 Standby $7,802792 $7,570299 -6.3.0% 20 Agriculture $173,247166,28

7 $179,187176,37

6 3.46.1%

21 E-20 T $215,899189,903

$216,219190,251

0.12%

22 E-20 P $420,026400,916

$411,639380,952

-25.0%

23 E-20 S $148,155140,969

$138,408128,477

-6.68.9%

24 System

$6,288,072081,332

$6,279,772067,464

-0.12%

TABLE 2A-2 REVENUE AND AVERAGE RATE SUMMARY AT PROPOSED RATES

Line No.

Revenue at May 1, 2020 Rates ($000)

Year 1 of Transition Cumulative Change After 3

Years

Revenue at Proposed

Rates ($000)

Class Average Percent

Change in Revenues

Revenue at Proposed

Rates ($000)

Class Average Percent Change

in Revenues

1 Bundled Summary 2 Residential $3,192,895180,

968 $3,178,664173

,297 -0.42% $3,165,9311

67,975 -0.841%

3 Small $836,199195 $850,065848,047

1.74% $878,688872,735

5.14.37%

4 Medium $734,656653 $729,472728,972

-0.78% $719,531718,134

-2.125%

5 E-19 $876,341284 $868,331122 -0.9% $851,319850,879

-2.990%

6 Streetlights $28,740 $27,822858 -3.21% $28,295405 -1.517% 7 Standby $82,651 $81,829786 -1.0% $80,07879,9

63 -3.125%

8 Agriculture $1,165,480156,635

$1,189,984178,265

2.1.9% $1,217,906208,556

4.549%

9 E-20 T $376,432447 $375,287406 -0.3% $373,519935 -0.867% 10 E-20 P $481,189047 $478,622477,4

96 -0.57% $472,330469

,015 -1.82.50%

11 E-20 S $212,534518 $208,883521 -1.79% $203,464202,413

-4.376%

12 System $7,987,115966,138

$7,988,958967,768

0.0% $7,991,061972,009

0.007%

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13 DA/CCA Summary 14 Residential $2,464,942408,

180 $2,442,624389

,825 -0.98% $2,396,1513

54,649 -2.822%

15 Small $881,026861,189

$906,279883,253

2.96% $957,282928,025

8.7.76%

16 Medium $812,935787,179

$818,595791,942

0.76% $828,800,516

2.01.69%

17 E-19 $1,136,686092,078

$1,130,775085,470

-0.56% $1,117,946071,464

-1.689%

18 Streetlights $27,35426,840 $26,17525,663 -4.34% $25,19124,684

-7.98.03%

19 Standby $7,802792 $7,757702 -0.61.2% $7,682540 -1.53.23% 20 Agriculture $173,247166,2

87 $168,879165,7

26 -2.50.3% $173,002169

,986 -0.12.22%

21 E-20 T $215,899189,903

$216,526190,482

0.3% $216,403190,390

0.226%

22 E-20 P $420,026400,916

$418,987398,043

-0.27% $416,048391,207

-0.92.42%

23 E-20 S $148,155140,969

$145,774138,142

-1.62.0% $142,828134,276

-3.64.75%

24 System $6,288,072081,332

$6,282,370076,250

-0.1% $6,281,332072,737

-0.114%

TABLE 2A-3 REQUIRED DISTRIBUTION AND GENERATION CHANGES FOR

EACH YEAR OF TRANSITION PLAN

Line No. Schedule

Distribution Annual Allocation Change

Generation Annual Allocation Change

1 E-1 / EL-1 -1.73% 1.54% 2 A-1 / A-6 / A-15 5.64.9% -1.0% 3 TC-1 5.64.9% 2.12% 4 A-10 T 6.35.1% 1.5% 5 A-10 P -2.5% -0.9% 6 A-10 S 1.74% -3.3% 7 E-19 T -6.37.4% 0.45% 8 E-19 P -2.24% 0.34% 9 E-19 S -1.67% -2.01.9%

10 Streetlights -8.9% 5.4.8% 11 Standby T -12.16% -0.53% 12 Standby P / S 0.5-1.3% -3.31% 13 AG-A 3.78% 2.34% 14 AG-B / C 2.12% 1.03% 15 E-20 T 0.0-1.9% -0.4% 16 E-20 P -1.12.7% -1.32% 17 E-20 S -3.09% -2.01.9%

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2-14

TABLE 2A-4 REVENUE IMPACTS OF PPP PROPOSED CHANGES

Line No. Rate Class

Revenue Impact From Distribution to PPP

Reclassification ($000)

Revenue Impact From Changing PPP

Allocation ($000)

Class Average Percent Change Bundled Rate

1 Residential ($798797) ($1,628546) -0.20% 2 Small ($149152) ($1,266239) -0.1% 3 Medium $166164 ($682656) 0.0% 4 E-19 $332329 $181216 0.10% 5 Streetlights $1110 ($1211) 0.0% 6 Standby $2421 ($2019) 0.10% 7 Agriculture ($287275) $3,917711 0.92% 8 E-20 T $243242 $424436 -0.2% 9 E-20 P $177176 $764781 0.10%

10 E-20 S $121 ($1,679673) -0.45% 11 System ($160161) $0 0.0%

(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 2

ATTACHMENT A

RATE DESIGN GUIDELINES TO IMPLEMENT REVENUE

REQUIREMENT CHANGES

(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 3

RESIDENTIAL RATE DESIGN

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3-i

PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 3

RESIDENTIAL RATE DESIGN

TABLE OF CONTENTS

A. Introduction ............................................................................................................ 3-1

1. PG&E’s 2018 RDW Proceeding Fixed Charge Proposal ............................. 3-2

2. Summary of PG&E’s Residential Rate Proposals in This Proceeding ........ 3-2

B. Residential Class................................................................................................... 3-5

C. Baseline Quantities – Gas and Electric ................................................................ 3-6

1. Introduction ..................................................................................................... 3-6

2. Normalization of Recorded Usage for Calculation of Proposed Electric and Gas Baseline Allowances Introduction ..................................... 3-7

a. Overview .................................................................................................. 3-7

b. Issues ....................................................................................................... 3-8

c. Proposal ................................................................................................. 3-10

d. Other Methods Considered ................................................................... 3-11

e. Proposed Baseline Allowances for Gas and Electric Residential Customers .............................................................................................. 3-12

3. Update Gas Master Metered Multifamily Service Schedule With End-Use Code W (GM-W) Baseline Allowance .......................................... 3-14

4. Move Gas Baseline Allowance Update to GCAP ....................................... 3-18

5. Baseline Territory Study ............................................................................... 3-19

6. Conclusion .................................................................................................... 3-20

D. Schedule E-1 Tiered Rates................................................................................. 3-20

1. Introduction ................................................................................................... 3-20

2. Schedule E-1 Rate Design........................................................................... 3-21

3. Rules for Changing E-1 Rates Between GRC Proceedings ...................... 3-21

E. TOU Rates ........................................................................................................... 3-22

1. Introduction ................................................................................................... 3-22

(PG&E-3) PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 3 RESIDENTIAL RATE DESIGN

TABLE OF CONTENTS

(CONTINUED)

3-ii

2. Default Schedule E-TOU-C.......................................................................... 3-22

3. Optional Schedules E-TOU-B and E-TOU-D .............................................. 3-26

a. Introduction............................................................................................. 3-26

b. Schedule E-TOU-B ................................................................................ 3-28

c. Schedule E-TOU-D ................................................................................ 3-29

4. Optional Schedule E-6 ................................................................................. 3-30

5. Optional Schedules EV and EV2 for Electric Vehicle Charging................. 3-33

a. Schedule EV .......................................................................................... 3-35

b. Schedule EV2 ........................................................................................ 3-36

6. Rules for Changing TOU Rates Between GRC Proceedings .................... 3-37

F. CARE Program .................................................................................................... 3-38

G. FERA Program .................................................................................................... 3-40

H. Medical Baseline Program .................................................................................. 3-41

I. SmartRate Program ............................................................................................ 3-42

J. Study on Feasibility of Remote Dispatch of Residential Battery Storage ........ 3-43

K. Master Meter Discounts ...................................................................................... 3-43

1. Marginal Cost Master Meter Discount Methodology .................................. 3-45

2. Diversity Benefit Adjustment ........................................................................ 3-49

a. Introduction............................................................................................. 3-49

b. Background ............................................................................................ 3-49

c. 2017 GRC Phase II Proposed DBA ...................................................... 3-51

d. PG&E’s Proposed 2020 GRC Phase II Diversity Benefit Adjustment ............................................................................................. 3-53

e. Impact of a Residential Fixed Monthly Charge on the DBA ................ 3-54

(PG&E-3) PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 3 RESIDENTIAL RATE DESIGN

TABLE OF CONTENTS

(CONTINUED)

3-iii

f. DBA Conclusion ..................................................................................... 3-56

3. Proposed Master Meter Discounts .............................................................. 3-57

L. Bill Comparisons ................................................................................................. 3-59

(PG&E-3)

3-1

PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 3 2

RESIDENTIAL RATE DESIGN 3

A. Introduction 4

This chapter presents Pacific Gas and Electric Company’s (PG&E or the 5

Company or the Utility) rate design proposals for its residential class of 6

customers, to be implemented pursuant to a decision in Phase II of its 7

2020 General Rate Case (GRC) Phase II (Phase II). As described in Exhibit 8

(PG&E-3), Chapter 1, “Revenue Allocation and Rate Design Policy,” these 9

proposals include changes to distribution, public purpose program (PPP), and 10

generation rate components. As discussed in Chapter 1, a key objective of 11

PG&E’s residential rate proposal is to use marginal cost relationships, balanced 12

with other objectives such as understandability, equity, and rate stability, to set 13

distribution and generation rates.1 PG&E sets forth its residential rate design 14

proposals in this testimony, focusing on changes to total bundled rates. 15

As discussed in Exhibit (PG&E-3), Chapter 1, PG&E is generally minimizing 16

rate design changes because it is proposing significant changes in marginal 17

cost-based revenue allocations at the class level that would, gradually over the 18

next six years, move each class to paying its fair share cost of serving that 19

class—no more and no less. That allocation proposal would, at the end of the 20

sixth year, result in a 1.4 percent reduction in the costs allocated to the 21

residential class. The California Public Utilities Commission (CPUC or 22

Commission) has already made major progress on residential rate 23

reform through its Residential Rate Reform Order Instituting Rulemaking 24

(RROIR) proceeding Rulemaking (R.) 12-06-013 and the 2018 Rate Design 25

Window (RDW) proceeding for the three major Investor-Owned Utilities (IOU) 26

(Application (A.) 17-12-011 et seq.), and PG&E’s proposals reflect those 27

RDW decisions. 28

1 PPP rates for the residential customer class are designed in accordance the guidelines

described in Exhibit (PG&E-3), Chapter 1.

(PG&E-3)

3-2

1. PG&E’s 2018 RDW Proceeding Fixed Charge Proposal 1

In Phase III of the 2018 RDW proceeding,2 PG&E proposed that the 2

current delivery minimum bill amount (DMBA) be replaced by a 3

$6.37-per-customer-month fixed charge, phased in over two years beginning 4

in 2022. In the alternative, should PG&E’s fixed charge proposal not be 5

adopted, PG&E’s contingency proposal was for the DMBA to be modified to 6

apply to just the distribution component of the rate, inclusive of the 7

Conservation Incentive Adjustment (CIA), rather than the entire 8

delivery rate.3 9

2. Summary of PG&E’s Residential Rate Proposals in This Proceeding 10

In summary, PG&E’s residential rate design proposals are as follows: 11

Baseline Quantities: 12

– Update residential electric baseline quantities, using 52.5 percent 13

of average usage, with the most recently available four years of 14

billing data and no changes to the current seasonal definitions 15

(i.e., a 4-month summer season consisting of June through 16

September and an 8-month winter season consisting of January 17

through May and October through December);4 and 18

– Revise gas baseline quantities at the same percentage of average 19

use as in previous GRC Phase II proceedings, but incorporate the 20

recently implemented segmentation of the gas winter season into a 21

2 A.17-12-011 (PG&E), A.17-12-012 (Southern California Edison Company (SCE)) and

A.17-12-013 (San Diego Gas & Electric Company), which the CPUC consolidated into a single proceeding.

3 This change to the DMBA was proposed by the Public Advocates Office at the California Public Utilities Commission. While PG&E believes a distribution minimum bill amount is an inferior rate design to one which includes a fixed charge, the distribution minimum bill amount would nevertheless represent an improvement over the current DMBA.

4 Schedule E-6 is the only residential rate that currently has different seasonal definitions, with a 6-month summer season consisting of May through October and a 6-month winter season consisting of January through April and November through December. Per Decision (D.) 15-11-013 in PG&E’s 2015 RDW Proceeding (A.14-11-014), however, on January 1, 2021 the seasonal definitions for Schedule E-6 will change and match those of all of PG&E’s other residential rates.

(PG&E-3)

3-3

2-month peak period of December and January and off -peak period 1

of November, February, and March.5 2

Tiered Rates: Establish rates for Schedule E-1 consistent with the 3

tiered rate ratios specified by D.15-07-001 for the final year of the 4

glidepath,6 but then freeze those cent-per-kilowatt hour (kWh) 5

differentials to prevent further widening should residential rates 6

increase. 7

Time-of-Use Rates: Establish rates for PG&E’s default time-of-use 8

(TOU) Schedule E-TOU-C, as well as PG&E’s menu of optional TOU 9

rates, consistent with D.19-07-004 in Phase IIB of the consolidated 10

2018 RDW proceeding and with D.15-11-013 in PG&E’s 2015 11

RDW proceeding.7 12

CARE Rates: Retain the 35 percent California Alternate Rates for 13

Energy (CARE) discount level that will become effective on March 1, 14

2020, per the glidepath established in D.15-07-001,8 but effectively 15

apply that 35 percent discount to all rate components, including the 16

DMBA, so that it represents a true, single-percentage, line-item 17

discount. 18

FERA Rates: Retain the current 18 percent Family Electric Rate 19

Assistance (FERA) discount level, but effectively apply that 18 percent 20

discount to all rate components, including the DMBA, so that it 21

represents a true, single-percentage, line-item discount. 22

Medical Baseline Rates: Retain the Medical Baseline structures 23

approved by D.18-08-013 in PG&E’s 2017 GRC Phase II proceeding, 24

but increase the DMBA from $5 to $10 consistent with the amount paid 25

by other non-CARE/FERA customers. 26

5 D.18-10-040, PG&E 2018 Gas Cost Allocation Proceeding, Decision Adopting

Settlement Agreement on Residential Baseline Season Restructuring. 6 D.15-07-001 is the Phase 1 decision in the Commission’s RROIR proceeding,

R.12-06-013. 7 A.14-11-014. 8 See D.15-07-001, p. 236, and PG&E Advice Letter (AL) 4697-E (approved by Energy

Division on November 12, 2015), p. 2.

(PG&E-3)

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Electric Vehicle Rates: Establish a Schedule EV rate transition for 1

solar grandfathered customers (reducing the TOU differentials to better 2

reflect current marginal costs). 3

SmartRate™: Retain the SmartRate design approved by D.18-12-004 4

in Phase IIA of the 2018 RDW. 5

Master Meter Discounts: Update the electric master meter discounts, 6

line loss adjustment (LLA), and baseline diversity benefit adjustment 7

(DBA) for Schedules ES, ESL, ET, and ETL using recent data. 8

Rate Changes Between GRC Phase II Proceedings: In D.18-08-013, 9

the Commission approved rules for changing rates when revenue 10

requirement changes occurred between GRC Phase II proceedings. 11

PG&E proposes the same rules in this proceeding for any changes due 12

to revenue requirement or reallocation of revenue, except as specifically 13

noted below. 14

These proposed residential rate changes, if adopted, would provide 15

more appropriate price signals for incenting more efficient energy usage 16

across a wide range of residential customers. 17

The remainder of this chapter is organized as follows: 18

Section B – Residential Class 19

Section C – Baseline Quantities – Gas and Electric 20

Section D – Schedule E-1 Tiered Rates 21

Section E – TOU Rates 22

Section F – CARE Program 23

Section G – FERA Program 24

Section H – Medical Baseline Program 25

Section I – SmartRate Program 26

Section J – Study on Feasibility of Remote Dispatch of Residential 27

Battery Storage 28

Section K – Master Meter Discounts 29

Section L – Bill Comparisons 30

Exhibit (PG&E-4), Appendix A, “Recorded Average Number of 31

Customers and Sales,” provides recorded 2017 and 2018 data for the 32

residential class. Exhibit (PG&E-4), Appendix C, “Present and Proposed 33

Rates,” and Attachment B to this chapter, contain PG&E’s present and 34

(PG&E-3)

3-5

proposed total and unbundled rates for the residential class. 1

Exhibit (PG&E-4), Appendix D, “Illustrative Bill Impacts of Present Versus 2

Proposed Rates,” presents bill impacts of PG&E’s proposed tiered 3

non-CARE and CARE rates. Finally, Exhibit (PG&E-4), Appendix F, 4

“Baseline Territory Study,” presents PG&E’s Baseline Territory Study 5

required by D.18-08-013. 6

B. Residential Class 7

PG&E’s residential class encompasses Schedules E-1, E-TOU-A, E-TOU-B, 8

E-TOU-C, E-TOU-D, E-6 (closed to new customers), EV-A, EV-B, EV2, EM, ES, 9

ESR, and ET.9 Most of PG&E’s residential customers are on the tiered, 10

non-TOU Schedule E-1, which is currently the standard rate, open to 11

any residential customer that is not master metered. Specifically, as of 12

November 2019, 87 percent of the approximately 4.8 million customers in 13

PG&E’s residential class are enrolled on E-1. 14

Customers who qualify for Schedule E-1 may also choose to take service on 15

PG&E’s optional TOU rates, E-TOU-A, E-TOU-B, and E-TOU-C. The rate with 16

the next largest enrollment after E-1 is Schedule E-TOU-A, which, as of 17

November 2019, had a customer enrollment of about 223,000, which represents 18

about five percent of PG&E’s residential customer population. 19

PG&E’s annual sales to the residential class are expected to be about 20

28,000 GWh (1 GWH = 1 million kWh) or 35 percent of PG&E’s total retail 21

electric sales in 2020. Income-qualified customers may enroll in either the 22

CARE or FERA discounted rate programs. CARE customers comprise about 23

24 percent of PG&E’s total residential customers, and FERA customers 24

represent another 0.5 percent. 25

Residential customers with an electric vehicle can take service under either 26

Schedule EV-A (1.1 percent of residential customers), EV-B (0.01 percent), or 27

new Schedule EV2 (0.1 percent). 28

Schedule EM, which is closed to new installations, provides service to 29

master metered multi-family residential customers without sub-metering, 30

9 Schedules E-6 and EV-A are closed to new customers, but available on a

grandfathered basis for legacy customers. Schedule E-TOU-A is expected to be eliminated effective September 30, 2020.

(PG&E-3)

3-6

including residential hotels as defined in PG&E’s Electric Rule 1,10 and 1

recreational vehicle (RV) parks which rent at least 50 percent of their spaces on 2

a month-to-month basis for at least nine months of the year to RV units used as 3

permanent residences. Schedule ES is open to master-metered multi-family 4

residential customers that serve sub-metered tenants, excluding sub-metered 5

mobile home parks (MHP). Schedule ESR is open to master-metered 6

residential RV parks or marinas where spaces, slips, or berths are rented on a 7

pre-paid monthly basis to RVs or boats used as permanent residences. 8

Schedule ET is open to master-metered MHPs which serve sub-metered 9

tenants. Schedules AM, ES, ESR and ET have the same energy and minimum 10

charges as Schedule E-1. 11

As established by the Commission in the 2018 RDW proceeding, beginning 12

in October 2020, PG&E is scheduled to begin its full roll-out of a default TOU 13

rate program to eligible residential customers.11 Customers who receive 14

notification of their impending default may opt-out of default TOU at any time, 15

and will receive bill protection for their first year on the rate such that, if they 16

would have been better off of E-1, they will receive a credit for the difference. 17

Another part of the CPUC’s already-adopted residential rate reforms, provides 18

that beginning in October 2020, Schedule E-TOU-C (the default TOU rate) will 19

be considered PG&E’s standard rate, although customer service representatives 20

will discuss with all new and transferring customers their available rate options. 21

Since the CPUC has already put so much effort into its residential rate 22

reform decisions, PG&E is limiting its residential rate design proposals in this 23

GRC Phase II proceeding. 24

C. Baseline Quantities – Gas and Electric 25

1. Introduction 26

Baseline quantities are the designated daily amounts of electricity and 27

gas that are considered necessary to supply a significant portion of the 28

reasonable energy needs of the average residential customer, pursuant 29

10 PG&E’s Electric Rule 1 can be found at the following link:

https://www.pge.com/tariffs/assets/pdf/tariffbook/ELEC_RULES_1.pdf. 11 A.17-12-011 et seq., which thus far has resulted in the following CPUC decisions:

D.18-05-011 (Phase 1), D.18-12-013 (Phase IIA), D.19-07-004 (Phase IIB).

(PG&E-3)

3-7

to California Public Utilities Code (Pub. Util. Code) Section 739, as 1

implemented by subsequent CPUC decisions. While residential and 2

non-residential gas rate design issues are generally litigated in the gas 3

Biennial Cost Adjustment Proceedings (BCAP), the proposed gas target 4

baseline quantities applicable during the 2020 GRC cycle have been 5

addressed in Phase II of the 2020 GRC, as ordered in D.89-12-057. 6

In this section, PG&E is proposing updated electric and gas baseline 7

quantities using a reversion to the previously-adopted methodology12 to use 8

weather-normalized, rather than unadjusted historic usage. As with the prior 9

method, under the proposed methodology PG&E averages the most recent 10

four calendar years of bill frequency-derived baseline quantities, but uses 11

normalized, rather than unadjusted data. As in the past, the methodology 12

also continues to exclude seasonal and vacation home usage, per 13

D.04-02-057, as modified in D.07-09-004. 14

Thus, the updated electric and gas baseline quantities proposed here 15

are calculated using four years of normalized historic usage. PG&E also 16

proposes updating the Gas Master Metered Multifamily Service Schedule 17

End-Use Code W Baseline Allowance and moving future updates of gas 18

baseline allowances to Gas Cost Allocation Proceedings (GCAP). 19

2. Normalization of Recorded Usage for Calculation of Proposed Electric 20

and Gas Baseline Allowances Introduction 21

a. Overview 22

As mentioned above, PG&E’s electric and gas baseline allowances 23

have historically been updated in prior GRC Phase II applications using 24

four years of unadjusted historic customer usage. In this proceeding, 25

PG&E proposes to weather-normalize recorded gas and electric 26

residential usage when calculating proposed baseline allowances. This 27

proposed change normalizes historic usage for any impacts caused by 28

volatile temperatures during the historic period. It also incorporates 29

non-temperature-related impacts on usage such as recent and forecast 30

test period changes in usage caused by reduced sales, such as from 31

customer employment of energy efficiency measures. 32

12 See D.02-04-026, which resolved the CPUC’s Baseline Rulemaking, R.01-05-047.

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PG&E makes this proposal for two reasons: (1) to reduce 1

unintended and undesirable fluctuations in baseline allowance levels 2

and resulting bill volatility adopted from one rate case baseline update to 3

the next; and (2) to better incorporate changes in customer usage in this 4

era of increasing energy transformation as reflected in the adopted 5

residential gas and electric sales forecasts. This proposal supports 6

Senate Bill (SB) 711 goals to consider bill volatility in gas and 7

electric rate design applications and is one of the methods authorized 8

by the Commission in D.04-04-026 for purposes of updating 9

baseline allowances. 10

b. Issues 11

Using four years of unadjusted recorded usage no longer provides a 12

stable basis to calculate proposed gas and electric baseline allowances. 13

Recorded Cooling Degree Days (CDD) and Heating Degree Days 14

(HDD) can vary widely and inconsistently among 4-year historic periods. 15

The change from one historic 4-year period used in a prior GRC 16

Phase II application to the historic 4-year period used in the next GRC 17

Phase II application has resulted in setting baseline allowances using 18

colder than normal13 data for one case and warmer than normal data for 19

another. To put it another way, total CDD’s or HDD’s in any given year 20

are rarely close to normal. Furthermore, in the analysis presented 21

below, even aggregating four years of data often results in average 22

CDD’s or HDD’s that are significantly different than normal. This can be 23

seen in the graphs Figures 3-1 and 3-2 below. 24

Further, the average temperatures underlying usage for the historic 25

4-year period for the current Phase II case can be colder than normal 26

while the temperatures underlying the usage data for the previous 27

Phase II historic period can be warmer than normal. The opposite 28

situation has also occurred. This results in baseline allowances, all else 29

held equal, that can swing in an unintended manner with each update. 30

While “normal” may be a moving target, there is significant fluctuation 31

13 Normal temperature usage forecasts represent the expected usage by the class

given the forecast number of customers under expected monthly Heating or Cooling Degree Days.

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in the average temperatures between one 4-year period and the 1

next 4-year period, making PG&E’s proposal to use the allowed 2

normalization method appropriate. This situation has occurred 3

three times in the past five GRC Phase II proceedings for gas and 4

electric baseline allowances, as indicated by the arrows in Figures 3-1 5

and 3-2.14 PG&E recently discovered this anomaly and is presenting its 6

analysis and proposed solution at its first opportunity in this 2020 7

GRC Phase II. 8

Additionally, climate change and the impacts of both energy 9

efficiency and electrification are transforming residential gas and electric 10

usage; that transformation can arguably be expected to take place at an 11

increasing pace going forward, when all three factors are combined.15 12

Therefore, it is important to have a forward-looking method for 13

calculating baseline allowances so that calculation of both gas and 14

electric baseline allowances use underlying usage data that are aligned 15

with the assumptions otherwise built into the calculation of gas and 16

electric rates in a way that does not contribute to bill volatility. 17

14 For example, one historic 4-year period, such as in the data used for the 2014 GRC

Phase II setting of baseline allowances was warmer than normal, and the 4-year historic period used in the following 2017 GRC Phase II was colder than normal.

15 There is a long-term decline in adopted and actual per-customer residential gas usage, as each year some portion of customers replace the following: 25-35-year-old gas furnaces with more efficient furnaces, 10-to-20-year-old gas water heaters with more efficient gas water heaters, instant demand water heating, solar water heaters, or even electric water heaters. Additionally, there is a long-term trend of customers replacing washing machines with more water-efficient front-loading and top-loading models and use of detergents that perform using cold water instead of having to use warm or hot . Furthermore, with the recent drought some customers have installed lower flow shower heads. These latter changes reduce the level of usage of gas-fired water heaters.

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FIGURE 3-1 HDD AVERAGE DURING 4-YEAR RECORDED PERIOD FOR EACH GRC PH II

AS % DIFFERENCE FROM 20-YR MOVING AVERAGE HDD’S

FIGURE 3-2 CDD AVERAGE DURING 4-YEAR RECORDED PERIOD

FOR EACH GRC PH II AS % DIFFERENCE FROM 20-YR MOVING AVERAGE CDD’S

c. Proposal 1

To address the increasingly dynamic environment of weather and 2

impacts from energy efficiency, water efficiency, and electrification on 3

residential gas and electric usage and appropriate baseline allowances, 4

PG&E proposes to normalize the four years of historical data used to 5

calculate gas and electric baseline quantities. To normalize the 6

recorded usage history PG&E determined: (1) the average usage per 7

residential customer segment (individually metered vs master metered) 8

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by month in the most recent forecast available;16 (2) the historical 1

average usage per customer by month by residential segment; (3) the 2

resulting monthly scaling factor by customer segment from dividing 3

(1) by (2); and then, (4) applied that scaling factor by month by 4

residential class segment to the historic usage by customer. 5

In its original testimony PG&E proposed to update its electric 6

baseline allowance showing to reflect the adopted 2020 Energy 7

Resource Recovery Account (ERRA) decision of its November 2019 8

update. However, because the residential sales forecast in the 9

November 2019 update adopted in the 2020 ERRA (D.20-02-047) is 10

identical (0.0000 percent difference) on an annual basis and differs in 11

any month by less than 0.00024 percent from the forecast filed by PG&E 12

in its June 2019 2020 ERRA application, the impact is inconsequential 13

and PG&E’s proposed allowances stand as originally filed. The 14

normalization of historic usage would limit the volatility in tiered rates 15

resulting from changes in baseline allowances between cases. Having 16

allowances and tiered rates commensurate with near-term future usage 17

will assist in meeting the goals of SB 711 by reducing bill volatility that is 18

not the result of intended price signals. The normalization would align 19

baselines with the adopted forecast of average usage per customer. 20

d. Other Methods Considered 21

PG&E’s initial exploration of this issue was related purely to the 22

CDD/HDD aspects impacting volatility of historic usage across updates. 23

PG&E originally considered a method that included expanding the 24

number of historic years used. However, to have a meaningful 25

reduction in the variance of CDD/HDD’s of the historic data sets 26

between cases, 10 years of historic usage data would be required for 27

each update filing. Using the 10 years of historical usage then presents 28

a major problem in that it does not reflect the current trends in energy 29

16 For this 2020 GRC Phase II application, the most recent adopted gas throughput and

customer forecast is from the 2019 Gas Transmission and Storage (GT&S) Rate Case that was adopted in PG&E’s GCAP (D.19-10-036). For electric normalization, the most recently filed parallel forecasts are in PG&E’s 2020 ERRA filed in June 2019 with a November 2019 update that does not change residential sales.

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efficiency and hot water conservation. Furthermore, it would not reflect 1

the continued energy efficiency impacts built into the usage forecast for 2

the upcoming rate case period, during which time the allowances would 3

be effective. 4

Ultimately, as PG&E continued to evaluate its proposal, it 5

determined that the only way to simply and completely incorporate all 6

the forces changing residential gas and electric usage would be to 7

normalize the recorded data to the most recent adopted forecast that is 8

already being used for all other rate design calculations. While one year 9

of historic usage data by customer could be used, using four years 10

of normalized customer usage provides additional diversity of 11

pre-normalized usage history among customers when determining 12

baseline allowances. 13

e. Proposed Baseline Allowances for Gas and Electric Residential 14

Customers 15

PG&E’s electric and gas baseline quantities were last adjusted in 16

D.18-08-013 (PG&E’s 2017 GRC Phase II). The adopted electric 17

allowances were implemented on January 1, 2019.17 The adopted gas 18

baseline quantities were implemented on November 1, 201918 after 19

incorporating the impacts of residential gas baseline seasonal 20

restructuring per D.18-10-040 and AL 4047-G. PG&E’s proposed 21

electric baseline quantities are calculated using 52.5 percent and 22

62.5 percent Tier 1 targets and using a 4-month summer season, as 23

adopted in D.18-08-013, consistent with Pub. Util. Code 24

Section 739(a)(1). Calculation of PG&E’s proposed gas baseline 25

quantities retains the adopted 60 percent target for summer and 26

70 percent target for winter, including peak and off -peak months, also 27

consistent with Pub. Util. Code Section 739(a)(1). 28

PG&E provides below, tables of its proposed baseline allowances 29

for gas and electric residential customers, updated using the most 30

17 AL 5429-E. 18 AL 4172-G.

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recently available four years of normalized historic usage data (which is 1

October 2014 to September 2018 for electric and November 2014 to 2

October 2018 for gas).19 As discussed above, PG&E’s proposal to use 3

normalized customer usage will provide customers with a long-term 4

stable trend of allowances for customers that reflect the usage levels the 5

Commission adopts for cost allocation and rate design purposes. This 6

mitigates allowance changes from update to update where the change is 7

dominated by periods of volatile weather. 8

Below, PG&E first presents its updated gas baseline allowances and 9

then presents the proposed electric baseline allowances, which include 10

a few post-calculation manual adjustments.20 11

i. Proposed Residential Gas Baseline Allowances (based on 12

four years of normalized historic usage) 13

TABLE 3-1 NEW GAS BASELINE DAILY QUANTITIES

BASED ON NOV 2014 THRU OCT 2018 NORMALIZED DATA

ii. Proposed Residential Electric Baseline Allowances for 4-month 14

summer/8-month winter schedules (based on four years of 15

normalized historic usage and including post-calculation proposed 16

adjustments). 17

19 The historic periods used for each commodity are aligned with the beginning of a

season change for that commodity. 20 The post-calculation proposed adjustments for the electric Baseline allowances are

described in PG&E’s electric baseline workpapers to Exhibit (PG&E-3).

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TABLE 3-2 NEW DAILY TARGET BASELINE QUANTITIES

BASED ON OCT 2014 THRU SEPT 2018 NORMALIZED TO FORECAST 52.5% TARGET: 4-MONTH SUMMER/8-MONTH WINTER

3. Update Gas Master Metered Multifamily Service Schedule With 1

End-Use Code W (GM-W) Baseline Allowance 2

PG&E proposes to update the GM-W baseline allowance quantity for the 3

2020 GRC and in future proceedings. The GM-W tariff applies to a subset 4

of PG&E’s master-metered customers, i.e., building owners, who supply 5

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only water heating from a central boiler to their tenants.21 The GM-W 1

baseline allowance was last updated to 0.5 therms per unit per day in 2

1984,22 and was fixed at 0.5 therms per unit per day in D.93198.23 PG&E 3

proposes to update that 0.5 therms value because it is out of date and does 4

not align with customer usage as of today, due to significantly increased 5

energy efficiency and water conservation measures. Furthermore, the 6

historically fixed 0.5 results in more customer usage being billed at the Tier 7

1 baseline rate than is appropriate under the ranges mandated for gas 8

usage by the California Pub. Util. Code.24 9

The two graphs below (Figures 3-3 and 3-4) illustrate (1) what the 10

GM-W allowances would have been in the previous four GRC Phase II 11

proceedings if they had not been fixed at 0.5 therms per unit per day; and 12

(2) how having the allowance fixed at 0.5 per therm per day has resulted in 13

a far higher percentage of total usage for GM-W master meter owners being 14

billed at the lower Tier 1 rates when compared to the Pub. Util. Code 15

maximum target percentages.25 16

21 Whether the master-metered customer receives the GM-W baseline quantities or the

regular GM (“Basic”) depends upon whether the tenants are individually metered by PG&E or not. If the tenants are individually metered, the landlord is assigned the GM-W designation. If the tenants do not have individual meters, the landlord is assigned the regular GM tariff and baseline allowance.

22 AL 1266-G and AL 1273-G, implementing D.83-12-068. 23 PG&E’s 1996 GRC Chapter 2 workpapers RD-2-4 notes “gas end-use W central water

heating customers…receive a fixed baseline quantity of 0.5 therms per day.” 24 Pub. Util. Code 739 (a) (1) specifies that the targets adopted by the Commission for

each gas utility should be based on 50-60 percent of summer usage being billed at Tier 1 rates, and 60-70 percent of winter usage being billed at Tier 1 rates.

25 The Commission has adopted gas targets of 60 percent for summer months and 70 percent for winter months for PG&E.

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FIGURE 3-3 ANNUAL BASELINE QUANTITIES “W” WITH ASSUMED GRC PH II DATA SET

DAILY THERMS PER UNIT

FIGURE 3-4 PERCENTAGE OF ANNUAL GM-W VOLUMES BILLED IN TIER 1

COMPARED TO PUB. UTIL. CODE MAXIMUM SEASONAL RANGES

Table 3-3 below presents a distribution of the annual bill impacts on the 1

owners of properties with service under tariff GM-W that would occur if the 2

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baseline allowance for GM-W were immediately updated. Over 53 percent 1

of GM-W customers would experience an annual gas bill increase of 2

10 percent or more. 3

Given the annual bill impact distribution for the owners of properties 4

receiving gas service under GM-W shown below, PG&E proposes to 5

phase-in the GM-W baseline allowance change over three years. The 6

distribution of impacts by annual bill cost and annual bill percentage change 7

under a 3-year phase-in is provided below in Table 3-4. With a 3-year 8

phase-in, only 8.5 percent of building owners would experience a first-year 9

bill impact of 7 or 8 percent, which would be the maximum impact 10

experienced by any GM-W customer from this proposed update. The 11

cumulative distribution of impacts in year three on customers of the 12

proposed 3-year phase-in is shown by Table 3-3. 13

TABLE 3-3 GM-W ANNUAL BILL IMPACT CUSTOMER SEGMENTATION %

YEAR 1 OF IMPLEMENTATION OF UPDATED GM-W BASELINE QUANTITY

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TABLE 3-4 GM-W ANNUAL BILL IMPACT CUSTOMER SEGMENTATION %

YEAR 1 OF 3-YEAR PHASE-IN OF UPDATED GM-W BASELINE QUANTITY

TABLE 3-5 BASELINE QUANTITY IN EACH PHASE-IN YEAR, BY SCENARIO

4. Move Gas Baseline Allowance Update to GCAP 1

The issue of gas baseline allowances has historically been addressed in 2

the GRC Phase II proceeding for PG&E, but PG&E believes it would be 3

more appropriate if in the future, this issue resided in PG&E’s GCAP. The 4

GCAP is the mirror-image proceeding on the gas side of GRC Phase II 5

dealing with cost allocation and rate design. PG&E proposes that the CPUC 6

move the determination of future baseline quantity updates to PG&E’s 7

GCAP, primarily to allow the CPUC to holistically consider it alongside the 8

impacts of cost allocation and gas rate design proposals, especially when 9

focusing on the tiered residential gas rates and residential gas rate 10

design.26 11

26 In the 2018 GCAP (D.19-10-036), PG&E’s proposal that future GCAPs be filed every

three to five years was adopted by the Commission. The Rate Case Plan (D.20-01-002) moves GRC Phase 1 rate cases to a 4-year cycle and orders Workshops to be held to review the scheduling of allocation cases with the inclusion of GT&S-related gas ratemaking into PG&E’s GCAP.

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However, PG&E proposes that any consideration of the potential future 1

issue of baseline territory boundary adjustments, as these territories are the 2

same for gas and electric customers, should remain in the GRC Phase II. 3

5. Baseline Territory Study 4

In its decision on PG&E’s 2017 GRC Phase II (D.18-08-013), the 5

Commission ordered PG&E to present three versions of its baseline territory 6

boundaries (and corresponding baseline allowances for each) in this 7

application. This was done: 8

…in order to provide the Commission with the opportunity to consider 9 new ways of defining Baseline territories that prioritize simplicity and 10 fairness for customers.27 11

PG&E has conducted the required study, which is presented in Exhibit 12

(PG&E-4), Appendix F. 13

This study presents the three versions of baseline territories required for 14

study by D.18-08-013 and evaluates their accuracy and fairness in 15

representing the relationship between microclimates and baseline 16

allowances, as well as other metrics such as stability and implementability. 17

Two of the three versions result in updates to PG&E’s existing territories, 18

while the third studies the status quo territories. Version 1 is an incremental 19

remapping of PG&E’s existing baseline territories based on grouping 20

customers by ZIP code and historical recorded data from nearby National 21

Weather Service (NWS) stations; Version 2 is a simplified smaller set of 22

territories created from scratch using the same set of ZIP code and NWS 23

historical data. PG&E finds that both the Version 1 and 2 revised territories 24

defined using the required ZIP-NWS analyses are unlikely to have greater 25

climate precision or fairness than PG&E’s existing baseline territories. 26

Furthermore, both Versions 1 and 2 would be difficult to implement and 27

cause instability in customer rates during this transitional period when the 28

Commission is already rolling out default TOU rates (and may also be 29

implementing a fixed charge rollout). PG&E therefore proposes that the 30

CPUC adopt the existing territories, while describing some of the needs for a 31

27 D.18-08-013, pp. 76-78 and Ordering Paragraphs (OP) 17-20.

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robust and reliable microclimate-driven baseline territory recalculation 1

should the CPUC wish to do so in PG&E’s 2023 GRC Phase II proceeding. 2

6. Conclusion 3

PG&E’s proposals to use four years of normalized historic residential 4

gas and electric usage data, update the GM-W Water Heating gas baseline 5

allowance, determine future gas allowances in GCAPs, and retain existing 6

baseline territory definitions are reasonable, supported by the testimony, 7

and should be adopted by the Commission. 8

D. Schedule E-1 Tiered Rates 9

1. Introduction 10

In D.15-07-001, the decision in Phase I of the RROIR proceeding, the 11

CPUC adopted a multi-year glide path that directed significant changes to 12

the structure and rates to be charged for usage under PG&E’s standard 13

tiered rates, Schedules E-1 and EL-1. The final step in PG&E’s glidepath 14

implementation for E-1 rates occurred on March 1, 2019, and those rates 15

now have three tiers that are defined as follows: 16

Tier 1: Usage between zero and 100 percent of baseline; 17

Tier 2: Usage between 100 and 400 percent of baseline; and 18

High Usage Surcharge (HUS) Tier: Usage above 400 percent 19

of baseline.28 20

Per the final step of D.15-07-001’s glidepath for tiered rates, the ratio of 21

the Tier 2 rate to the composite Tier 1 rate is 1.25-to-1 and the ratio of the 22

HUS rate to the composite Tier 1 rate is 2.19-to-1.29 23

In D.19-07-004 in Phase IIB of the 2018 RDW proceeding, the 24

Commission determined that, beginning in October 2020, default TOU rate 25

Schedule E-TOU-C will become the standard turn-on rate for PG&E’s new 26

and transfer residential customers. These TOU rates are discussed in 27

28 D.15-07-001 refers to this charge for usage above 400 percent of Baseline as the

Super-User Electric Surcharge. However, on July 27, 2016, PG&E requested in AL 4722-E-B to modify the name of the surcharge to “High Usage Surcharge,” which was approved by the CPUC’s Energy Division on August 24, 2016.

29 D.15-07-001, mimeo, p. 278. The composite Tier 1 rate is calculated by adding any revenues from a fixed charge and/or a minimum bill amount to the Tier 1 energy revenues, and then dividing by the Tier 1 sales.

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Section E of this chapter. Schedule E-1 will remain available as an optional 1

rate, should a customer prefer to be served on a tiered non-TOU rate. 2

2. Schedule E-1 Rate Design 3

PG&E has designed illustrative E-1 rates based upon (a) its proposed 4

revenue allocation in this proceeding; (b) the final steps of the glidepath for 5

tiered rate ratios specified in D.15-07-001; and (c) forecasted billing 6

determinants (i.e., sales by tier) based upon the baseline quantities 7

proposed in Section B. These rates are shown in Appendix C of 8

Exhibit (PG&E-4). 9

3. Rules for Changing E-1 Rates Between GRC Proceedings 10

In GRC Phase II proceedings, the Commission typically adopts not only 11

a rate design for each schedule, but also a set of rules for how rates should 12

change during the period between when the rates are adopted and the 13

following GRC Phase II proceeding (which, for PG&E, is anticipated to be 14

the 2023 GRC Phase II). While PG&E is proposing that rates in this 15

proceeding initially match the D.15-07-001 end-state glidepath ratios of 16

1.25-to-1 between Tier 2 and Tier 1 rates, and 2.12-to-1 between the HUS 17

and Tier 1 rates, PG&E is concerned that adherence to these ratios may, 18

over time, cause a widening of the cent-per-kWh differentials between the 19

tiered rates. This is exactly what happened in the years after the energy 20

crisis and was one of the main problems the Residential Rate Reform 21

Proceeding (R.12-06-013) was opened to address. 22

PG&E’s HUS rate today is almost 54 cents per kWh.30 If it is 23

constrained in the future to always be 2.12 times the composite Tier 1 rate, it 24

could rapidly escalate to even higher levels in the future. To a somewhat 25

lesser degree, constraining the Tier 2 rate to always be 1.25 times the 26

composite Tier 1 rate might also cause a rapidly-widening cent-per-kWh 27

difference between Tier 2 and Tier 1 rate. Both of these would adversely 28

affect the high bill problem that already exists in the Central Valley, where 29

an inclining block tier structure combines with high summer usage to create 30

high bills and bill volatility. 31

30 Effective May 1, 2020, the Schedule E-1 HUS rate is $0.53738 per kWh.

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To mitigate against this potential problem in the future, PG&E proposes 1

instead to change rates between GRCs by fixing the cent-per-kWh at their 2

levels reached at the end of 2022. Under this proposal, the tiered rates 3

would initially be set to match the end-state glidepath ratios, as described in 4

the previous section. However, effective January 1, 20132023, any 5

increases or decreases in rates would be implemented by changing the rate 6

levels in each tier by an equal cents per kWh amount. Thus, if, for example, 7

rates needed to be increased by one cent-per-kWh to collect a future 8

authorized revenue requirement, all three of the tiered rates would go up by 9

that one cent amount, leaving the cent-per-kWh differentials between the 10

tiered rates unchanged.31 11

E. TOU Rates 12

1. Introduction 13

PG&E’s TOU rate offerings to residential customers are in a process of 14

transition. For many years, residential TOU rates were voluntary and 15

required customers to opt in if they wished to take service on a TOU rate. In 16

October 2020, though, eligible customers on Schedule E-1 will begin being 17

defaulted to PG&E’s recently approved default TOU rate, Schedule 18

E-TOU-C, with the ability to opt-out back to E1 should they so desire. That 19

rate will also become PG&E’s standard turn-on rate for new customers or 20

transfer customers (who have moved locations within PG&E’s service area). 21

The following sections describe PG&E’s proposals for its various TOU rate 22

options, some of which are now closed (or soon will be) to new and transfer 23

customers but are still in place for customers on a grandfathered basis. 24

2. Default Schedule E-TOU-C 25

In its Phase IIB decision in the 2018 RDW, D.19-07-004, the 26

Commission approved PG&E’s proposed Schedule E-TOU-C as its default 27

TOU rate. Schedule E-TOU-C has two tiers, with two TOU periods in 28

summer (peak and off-peak) and two TOU periods in winter (peak and 29

31 As described below in Sections F and G, E-1 customers who qualify for either CARE or

FERA would continue to receive line-item discounts (35 percent for CARE, 18 percent for FERA) off their calculated E-1 bills.

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off-peak), as shown in Table 3-6. Per D.19-07-004, PG&E plans to begin 1

transitioning non-excluded customers32 to Schedule E-TOU-C beginning in 2

October 2020, with the transition occurring in waves over a 13- to 18-month 3

period.33 Customers who do not wish to be defaulted to Schedule E-TOU-C 4

can opt out and choose another available residential rate (e.g., tiered 5

Schedule E-1, or another opt-in TOU rate). All customers who are defaulted 6

to, and choose to remain on, Schedule E-TOU-C will receive 12 months of 7

bill protection.34 8

TABLE 3-6 SCHEDULE E-TOU-C PERIOD DEFINITIONS

32 Customers to be excluded are as follows: Medical Baseline customers; customers

requesting third-party notification pursuant to Pub. Util. Code Section 779.1(c); customers who the Commission has ordered cannot be disconnected without an in-person visit from a PG&E representative; customers with less than 12 months of metered interval data; customers for whom PG&E cannot complete the rate comparison analyses required pursuant to Pub. Util. Code Section 745; customers already on a TOU rate; customers who participated in PG&E’s default TOU pilot; customers eligible for PG&E’s CARE or FERA programs who reside in hot climate zones; master-metered customers; customers taking service on certain net energy metering (NEM) programs; participants in the Multifamily Affordable Solar Housing or the Solar on Multifamily Affordable Housing programs; or Transition Bundled Service customers. (D.19-07-004, OP 27).

33 Prior to the October 2020 start of the default TOU transition period, customers can choose service on Schedule E-TOU-C by opting into the rate.

34 Bill protection ensures that, over the 12-month period after being defaulted, the total E-TOU-C bill of a defaulted customer will be no higher than it would have been if the customers had opted out back to Schedule E-1. Customers who initially stay on E-TOU-C but then change their minds and opt out prior to the end of the 12-month bill protection period, will receive bill protection for the months during which they were on E-TOU-C.

Effective March 1, 2020 Months Weekdays Weekends/Holidays

Summer Peak June - September 4 p.m. - 9 p.m. 4 p.m. - 9 p.m.

Summer Off-Peak June - September Midnight - 4 p.m.,9 p.m. - Midnight

Midnight - 4 p.m.,9 p.m. - Midnight

Winter Peak October - May 4 p.m. - 9 p.m. 4 p.m. - 9 p.m.

Winter Off-Peak October - May Midnight - 4 p.m.,9 p.m. - Midnight

Midnight - 4 p.m.,9 p.m. - Midnight

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In its Phase IIB decision, the Commission approved PG&E’s proposal 1

for “TOU Lite” peak versus off-peak (POPP) rate differentials, in order to 2

ease the transition of customers onto the default TOU rate and increase the 3

likelihood of their remaining on the rate after the bill protection period ends. 4

Specifically, D.19-07-004 approved PG&E’s proposal for a summer POPP 5

of 6.3 cents/kWh and a winter POPP of 1.7 cents/kWh. The decision further 6

specified that a portion of both the 6.3 cent summer and the 1.7 cent POPP 7

differentials be included in the distribution rate component. Specifically, 8

D.19-07-004 directs that at least 1 cent of the 6.3 cent summer POPP 9

differential and exactly 0.23 cents of the 1.7 cent winter POPP differential be 10

included in the distribution rate.35 On October 9, 2019, PG&E filed 11

AL 5653-E to implement this directive, effective March 1, 2020.36 Finally, 12

OP 5 of D.19-07-004 also directed PG&E to include revised summer and 13

winter POPP differentials in its 2020 GRC Phase II application for 14

consideration by the parties and the Commission. 15

Per D.19-07-004, PG&E is scheduled to begin defaulting customers to 16

E-TOU-C in waves starting in October 2020, a process which is expected to 17

conclude within 18 months. That decision also directed that defaulted 18

customers initially experience a “TOU Lite” rate design, with mild POPP 19

differentials of 6.3 and 1.7 cents in summer and winter, respectively. Thus, 20

in order for the last wave of defaulted customers to be able to experience a 21

full twelve months of TOU Lite rates, and then receive their bill protection 22

statement, these mild initial E-TOU-C POPP differentials need to be in place 23

for at least 13 months after the last wave of customers are defaulted to 24

E-TOU-C. This will ensure that all defaulted customers have had the 25

opportunity to become accustomed to TOU after at least one year of TOU 26

Lite rates and received their final bill protection notice (which shows the 27

degree to which they saved, or did not save, on E-TOU-C). Thus PG&E 28

35 D.19-07-004, OPs 6 and 7. 36 PG&E’s rate design proposes that exactly 1 cent of the total 6.3 cent summer POPP

differential be in the distribution rate, with the other 5.3 cents in the generation rate. AL 5653-E was approved on January 6, 2020 and the new Schedule E-TOU-C rates went into effect on March 1, 2020.

(PG&E-3)

3-25

proposes to maintain its approved TOU Lite rates through the end 1

of 2022.37 2

Table 3-7 presents current (in yellow) and proposed (in blue) POPP 3

differentials for Schedule E-TOU-C, as well as the underlying marginal 4

generation and primary distribution costs (in orange). In summer, the 5

current E-TOU-C POPP differentials are 5.3 and 1.0 cents for generation 6

and distribution, respectively, compared to the marginal cost target 7

differentials of 16.917.3 and 9.4 cents. PG&E’s proposal is to gradually 8

widen the current “TOU Lite” POPP differentials, effective no earlier than 9

January 1, 2023, by increasing both the generation and distribution summer 10

POPP differentials by 1.0 cents each. This would result in an increase in the 11

total summer POPP differential of 2.0 cents. In winter, the current POPP 12

differentials for generation and distribution are 1.5 and 0.2 cents, compared 13

to marginal cost differentials of 3.9 and 0.3 cents. PG&E’s proposal is to 14

increase the winter generation POPP differential by 1.0 cents to 2.5 cents, 15

and to increase the winter distribution POPP differential by 0.1 cents to hit 16

the 0.3 cent marginal cost target differential. This would result in a 1.1 cent 17

increase to the total winter POPP differential. As noted above, these wider 18

TOU price differentials would go into effect no sooner than 13 months after 19

customers in the last wave have been defaulted to the E-TOU-C rate. 20

37 In order to not alter the relative attractiveness of its menu of open rate opt ions from

which customers will be choosing, PG&E proposes no change to the design of Schedules E-TOU-C, E-1, and E-TOU-D until January 1, 2023, at the earliest. For closed legacy Schedules E-TOU-B, E-6, and EV, though, PG&E proposes to implement the design changes described herein effective January 1, 2022 (assuming a decision in this proceeding is issued in time to do so).

(PG&E-3)

3-26

TABLE 3-7 SCHEDULE E-TOU-C RATE DIFFERENTIALS VS. FULL MARGINAL COST DIFFERENTIALS

($/KWH)

3. Optional Schedules E-TOU-B and E-TOU-D 1

a. Introduction 2

Currently, PG&E offers its customers, on an optional basis, a 3

non-tiered TOU rate called Schedule E-TOU-B.38 Schedule E-TOU-B 4

has two TOU periods in summer (peak and off-peak) and two TOU 5

periods in winter (peak and off-peak), as shown in Table 3-8 below. 6

38 As of the date this testimony is being filed, PG&E also offers its residential customers

an optional tiered TOU rate, Schedule E-TOU-A. However, in its final decision in Phase IIB of PG&E’s 2018 RDW, the Commission authorized PG&E to eliminate Schedule E-TOU-A in 2020 (See D.19-07-004, OP 11, and subsequent PG&E AL 5654-E). PG&E plans to migrate all E-TOU-A customers to E-TOU-C (or, if the customer does not wish to take service on E-TOU-C, to any other residential rate option for which the customer is eligible) beginning with their July 2020 billing cycle, after which Schedule E-TOU-A will be eliminated. Consequently, PG&E has not designed rates for E-TOU-A in this proceeding.

Generation Distribution Total Generation Distribution Total Generation Distribution Total

Summer Peak vs. Off-Peak $0.053 $0.010 $0.063 $0.063 $0.020 $0.083 $0.169 $0.094 $0.263

Winter Peak vs. Off-Peak $0.015 $0.002 $0.017 $0.025 $0.003 $0.028 $0.039 $0.003 $0.042

Schedule E-TOU-CCurrent Rate Differentials Proposed Rate Differentials Full Marginal Cost Target Differentials

Generation Distribution Total Generation Distribution Total Generation Distribution Total

Summer Peak vs. Off-Peak $0.053 $0.010 $0.063 $0.063 $0.020 $0.083 $0.173 $0.094 $0.267

Winter Peak vs. Off-Peak $0.015 $0.002 $0.017 $0.025 $0.003 $0.028 $0.039 $0.003 $0.043

Schedule E-TOU-CCurrent Rate Differentials Proposed Rate Differentials Full Marginal Cost Target Differentials

(PG&E-3)

3-27

TABLE 3-8 SCHEDULE E-TOU-B PERIOD DEFINITIONS

In Phase IIB of the 2018 RDW, PG&E proposed to narrow the peak 1

period on Schedule E-TOU-B from the current 5-hour period from 2

4-9 p.m., to a 3-hour period from 5-8 p.m. D.19-07-004 approved 3

PG&E’s proposal to offer this revised TOU rate to new customers, but 4

also directed PG&E to retain, the current Schedule E-TOU-B periods for 5

“legacy” customers already taking service on the rate for a limited time 6

period, until October 2025.39 7

To implement this decision, PG&E plans to close 8

Schedule E-TOU-B to new customers on May 1, 2020. All customers 9

who were on E-TOU-B as of April 30, 2020 may remain on the rate with 10

unchanged TOU period definitions until it is eliminated on October 31, 11

2025. At that time, all remaining Schedule E-TOU-B customers will be 12

defaulted to Schedule E-TOU-D, unless they opt out to a different 13

available residential rate option. 14

In order to avoid confusion with the legacy E-TOU-B rate for 15

grandfathered customers, PG&E proposes to name the modified version 16

of E-TOU-B approved by D.19-07-004 (with the narrower 3-8 p.m. peak 17

period hours) “Schedule E-TOU-D.” The Schedule E-TOU-D TOU 18

period definitions are shown below in Table 3-9. 19

39 See D.19-07-004, OP 12. On October 9, 2019, PG&E submitted AL 5655-E to

implement these directives.

Current(Through October 1, 2025)

Months Weekdays Weekends/Holidays

Summer Peak June - September 4 p.m. - 9 p.m. NA

Summer Off-Peak June - September Midnight - 4 p.m.,9 p.m. - Midnight Midnight - Midnight

Winter Peak October - May 4 p.m. - 9 p.m. NA

Winter Off-Peak October - May Midnight - 4 p.m.,9 p.m. - Midnight Midnight - Midnight

(PG&E-3)

3-28

TABLE 3-9 SCHEDULE E-TOU-D PERIOD DEFINITIONS

b. Schedule E-TOU-B 1

Since its inception, Schedule E-TOU-B has had time-differentiation 2

only in the generation rate. While D.19-07-004 directed PG&E to 3

include time-differentiation in Schedules E-TOU-C and E-TOU-D, it left 4

the design for the soon-to-be-closed Schedule E-TOU-B unchanged. 5

Focusing on just the generation rate component in Table 3-10 below, 6

the current summer and winter POPP differentials of 10.3 and 1.9 cents, 7

respectively, are smaller than the corresponding marginal cost target 8

differentials of 21.922.8 and 4.47 cents. Accordingly, PG&E is 9

proposing to increase the summer and winter generation POPP 10

differentials, respectively, by 2.0 cents each to 12.3 and 3.9 cents, 11

effective January 1, 2022.40 This achieves the objective of gradually 12

moving the POPP differentials closer to their marginal cost targets, while 13

mitigating potential rate shock. 14

40 PG&E generally changes its rates every January 1 to implement rate changes resulting

from its Annual Electric True-Up (AET). Since PG&E anticipates the Commission will be issuing a final decision in this proceeding around mid-2021, this widening of the generation POPP differential would occur as part of the first AET-related rate change after the 2020 GRC Phase II decision is issued.

Effective May 1, 2020 Months Weekdays Weekends/Holidays

Summer Peak June - September 5 p.m. - 8 p.m. NA

Summer Off-Peak June - September Midnight - 5 p.m.,8 p.m. - Midnight Midnight - Midnight

Winter Peak October - May 5 p.m. - 8 p.m. NA

Winter Off-Peak October - May Midnight - 5 p.m.,8 p.m. - Midnight Midnight - Midnight

(PG&E-3)

3-29

TABLE 3-10 SCHEDULE E-TOU-B RATE DIFFERENTIALS VS. FULL MARGINAL COST DIFFERENTIALS

($/KWH)

c. Schedule E-TOU-D 1

Table 3-11 shows the current and proposed POPP differentials for 2

non-tiered Schedule E-TOU-D, along with the associated marginal cost 3

target differentials. D.19-07-004 approved summer generation and 4

distribution POPP differentials of 8.5 and 1.0 cents, with much smaller 5

winter generation and distribution POPP differentials of 1.5 and 6

0.2 cents. The table shows that PG&E’s new marginal cost target 7

differentials developed for this proceeding are all larger than these rate 8

differentials. Accordingly, PG&E is proposing that, effective no earlier 9

than January 1, 2023, the summer generation and distribution POPP 10

differentials, as well as the winter generation POPP differential, all be 11

increased by 2.0 cents. Because the winter distribution POPP 12

differential is less than 1.0 cents from its marginal cost target, PG&E 13

proposes to increase this POPP differential by about 0.2 cents so that it 14

hits the target. These proposals will gradually bring all the POPP 15

differentials much closer to (and, in the case of the winter distribution 16

POPP differential, exactly to) their marginal cost targets—allowing 17

customers to gradually adjust to stronger price incentives to shift load, 18

while offering another differentiated TOU option. 19

Generation Distribution Total Generation Distribution Total Generation Distribution Total

Summer Peak vs. Off-Peak $0.103 $0.000 $0.103 $0.123 $0.000 $0.123 $0.219 $0.076 $0.295

Winter Peak vs. Off-Peak $0.019 $0.000 $0.019 $0.039 $0.000 $0.039 $0.044 $0.004 $0.048

Schedule E-TOU-BCurrent Rate Differentials Proposed Rate Differentials Full Marginal Cost Target Differentials

Generation Distribution Total Generation Distribution Total Generation Distribution Total

Summer Peak vs. Off-Peak $0.103 $0.000 $0.103 $0.123 $0.000 $0.123 $0.228 $0.076 $0.304

Winter Peak vs. Off-Peak $0.019 $0.000 $0.019 $0.039 $0.000 $0.039 $0.047 $0.004 $0.051

Schedule E-TOU-BCurrent Rate Differentials Proposed Rate Differentials Full Marginal Cost Target Differentials

(PG&E-3)

3-30

TABLE 3-11 SCHEDULE E-TOU-D RATE DIFFERENTIALS VS. FULL MARGINAL COST DIFFERENTIALS

($/KWH)

4. Optional Schedule E-641 1

PG&E’s Schedule E-6 is a legacy tiered TOU rate that has been closed 2

to new customers since May 31, 2016, but remains open for grandfathered 3

customers through 2022.42 Schedule E-6 has two tiers, along with three 4

TOU periods in summer (peak, partial-peak, and off-peak) and two TOU 5

periods in winter (partial-peak and off-peak). In D.15-11-013, the 6

Commission approved a settlement that will phase out Schedule E-6 at the 7

end of 2022. The phase-out schedule will, over time, change the summer 8

and winter seasonal definitions, as well as the TOU period hours, as shown 9

in Table 3-12 below. Schedule E-6 will be eliminated at the end of 2022. All 10

grandfathered customers still on Schedule E-6 at that time will be 11

transitioned to PG&E’s default TOU rate (Schedule E-TOU-C), unless they 12

elect a different optional rate schedule.43 13

41 The Schedule E-6 rate design also applies to master-metered Schedule EM TOU. 42 Grandfathered customers are those who took service on the rate on or before May 31,

2016. 43 The settlement adopted by D.15-11-013 states that remaining Schedule E-6 customers

be transitioned to PG&E’s then-existing default TOU rate. Since that decision, the Commission, in Phase IIB of the 2018 RDW proceeding, determined that PG&E’s default TOU rate will be Schedule E-TOU-C. (See D.19-07-004.).

Generation Distribution Total Generation Distribution Total Generation Distribution Total

Summer Peak vs. Off-Peak $0.085 $0.010 $0.095 $0.105 $0.030 $0.135 $0.176 $0.085 $0.261

Winter Peak vs. Off-Peak $0.015 $0.002 $0.017 $0.035 $0.004 $0.039 $0.053 $0.004 $0.056

Current Rate Differentials Proposed Rate Differentials Full Marginal Cost Target Differentials Schedule E-TOU-D

Generation Distribution Total Generation Distribution Total Generation Distribution Total

Summer Peak vs. Off-Peak $0.085 $0.010 $0.095 $0.105 $0.030 $0.135 $0.152 $0.085 $0.237

Winter Peak vs. Off-Peak $0.015 $0.002 $0.017 $0.035 $0.004 $0.039 $0.057 $0.004 $0.060

Current Rate Differentials Proposed Rate Differentials Full Marginal Cost Target Differentials Schedule E-TOU-D

(PG&E-3)

3-31

TABLE 3-12 SCHEDULE E-6 TOU PERIOD DEFINITIONS

Current (Through 2020) Months Weekdays Weekends/Holidays

Summer Peak May - October 1 p.m. - 7 p.m. NA

Summer Partial-Peak May - October 10 a.m. - 1 p.m.,7 p.m. - 9 p.m. 5 p.m. - 8 p.m.

Summer Off-Peak May - October Midnight - 10 a.m.,9 p.m. - Midnight

Midnight - 5 p.m.,8 p.m. - Midnight

Winter Partial-Peak November - April 5 p.m. - 8 p.m. NA

Winter Off-Peak November - April Midnight - 5 p.m.,8 p.m. - Midnight Midnight - Midnight

2021 Months Weekdays Weekends/Holidays

Summer Peak June - September 3 p.m. - 8 p.m NA

Summer Partial-Peak June - September Noon - 3 p.m.,8 p.m. - 10 p.m. 5 p.m. - 8 p.m.

Summer Off-Peak June - September Midnight - Noon,10 p.m. - Midnight

Midnight - 5 p.m.,8 p.m. - Midnight

Winter Partial-Peak October - May 5 p.m. - 8 p.m. NA

Winter Off-Peak October - May Midnight - 5 p.m.,8 p.m. - Midnight Midnight - Midnight

2022 Months Weekdays Weekends/Holidays

Summer Peak June - September 4 p.m. - 9 p.m. NA

Summer Partial-Peak June - September 2 p.m. - 4 p.m.,9 p.m. - 10 p.m. 5 p.m. - 8 p.m.

Summer Off-Peak June - September Midnight - 2 p.m.,10 p.m. - Midnight

Midnight - 5 p.m.,8 p.m. - Midnight

Winter Partial-Peak October - May 5 p.m. - 8 p.m. NA

Winter Off-Peak October - May Midnight - 5 p.m.,8 p.m. - Midnight Midnight - Midnight

(PG&E-3)

3-32

For purposes of this proceeding, PG&E designed rates based on its 1

2021 seasonal and TOU period definitions.44 Table 3-13 presents the 2

current peak versus off-peak and part-peak versus off-peak rate differentials 3

(in yellow, which correspond to today’s TOU period definitions), along with 4

the corresponding marginal cost differentials (in orange, which correspond 5

to the 2021 TOU period definitions). For summer generation rates, the 6

current peak versus off-peak price and part-peak versus off-peak 7

differentials are 17.3 and 5.0 cents, respectively. In comparison, the 8

analogous marginal cost differentials are 15.113.7 and 14.517.6 cents. So, 9

PG&E is proposing to reduce the peak versus off -peak differential by 10

2.0 cents to 15.3 cents and increase the part-peak versus off-peak 11

differential by 2.0 cents 7.0 cents, to bring both closer to their generation 12

marginal cost target differentials. The current winter generation peak versus 13

off-peak rate differential is 1.4 cents compared to the marginal generation 14

cost differential of 5.37 cents. Here, PG&E is proposing a 2.0 cent increase 15

to this differential, bringing it to 3.4 cents to better reflect marginal costs. 16

TABLE 3-13 SCHEDULE E-6 RATE DIFFERENTIALS VS. FULL MARGINAL COST DIFFERENTIALS

($/KWH)

For summer distribution rates, the current peak versus off -peak 17

differential of 24.3 cents vastly exceeds the 9.7 cent marginal cost target, so 18

44 Typically, it has taken at least 18 months from the time a GRC Phase II Application is

filed for the Commission to issue a final decision. Since PG&E is filing this application on November 22, 2019, a final decision is not anticipated any earlier than June 2021.

Generation Distribution Total Generation Distribution Total Generation Distribution Total

Summer Peak vs. Off-Peak $0.173 $0.243 $0.417 $0.153 $0.223 $0.377 $0.151 $0.097 $0.248

Summer Part-Peak vs. Off-Peak $0.050 $0.061 $0.111 $0.070 $0.050 $0.120 $0.145 $0.050 $0.195

Winter Part-Peak vs. Off-Peak $0.014 $0.039 $0.053 $0.034 $0.019 $0.053 $0.053 $0.004 $0.056

Proposed Rate Differentials Full Marginal Cost Target Differentials Schedule E-6

Current Rate Differentials

Generation Distribution Total Generation Distribution Total Generation Distribution Total

Summer Peak vs. Off-Peak $0.173 $0.243 $0.417 $0.153 $0.223 $0.377 $0.137 $0.097 $0.233

Summer Part-Peak vs. Off-Peak $0.050 $0.061 $0.111 $0.070 $0.050 $0.120 $0.176 $0.050 $0.226

Winter Part-Peak vs. Off-Peak $0.014 $0.039 $0.053 $0.034 $0.019 $0.053 $0.057 $0.004 $0.060

Proposed Rate Differentials Full Marginal Cost Target Differentials Schedule E-6

Current Rate Differentials

(PG&E-3)

3-33

PG&E is proposing to decrease it by 2.0 cents to 22.3 cents. The 6.1 cent 1

part-peak versus off-peak differential, though, only slightly exceeds the 2

5.0 cent marginal cost target, so PG&E is proposing to decrease it by 3

1.1 cents to match the target. For winter distribution rates, the 3.9 cent 4

part-peak versus off-peak differential is 3.5 cents higher than the 0.4 cent 5

marginal cost target, so PG&E proposes to decrease it by 2.0 cents to 6

1.9 cents. PG&E proposes that these changes take effect on January 1, 7

2022. 8

5. Optional Schedules EV and EV2 for Electric Vehicle Charging 9

PG&E currently maintains two non-tiered TOU rate schedules for 10

electric vehicle charging: Schedules EV and EV2. Schedule EV was 11

developed prior to when the influx of solar power shifted the high-cost 12

generation hours from afternoon to later in the day. It has peak period hours 13

from 2-9 p.m. on weekdays and from 3-7 p.m. on weekends and holidays, 14

as shown in Table 3-14. Schedule EV customers can choose between 15

two options: (1) a whole-house charging option on Rate A, where the 16

household’s entire usage is billed on the rate; or (2) a separately-metered 17

option on Rate B, where the customer has a second meter on its EV charger 18

(with the remainder of the household loads being metered and billed 19

separately on a different residential rate). Option A of Schedule EV is now 20

closed to new customers, available only on a grandfathered basis to legacy 21

customers, while Option B remains available to new enrollment. 22

(PG&E-3)

3-34

TABLE 3-14 SCHEDULE EV TOU PERIOD DEFINITIONS

With the closing of Option A of Schedule EV, PG&E now offers 1

customers seeking a whole-house charging option a new Schedule EV2, 2

approved by the Commission in D.18-08-013, with peak period hours every 3

day from 4-9 p.m. This better reflects the times of day when PG&E’s costs 4

are now the highest. The Schedule EV2 TOU period definitions are shown 5

in Table 3-15. 6

TABLE 3-15 SCHEDULE EV2 TOU PERIOD DEFINITIONS

Current (ThroughNovember 2025)

Months Weekdays Weekends/Holidays

Summer Peak May - October 2 p.m. - 9 p.m. 3 p.m. - 7 p.m.

Summer Partial-Peak May - October 7 a.m. - 2 p.m.,9 p.m. - 11 p.m. NA

Summer Off-Peak May - October Midnight - 7 a.m.,11 p.m. - Midnight

Midnight - 3 p.m.,7 p.m. - Midnight

Winter Peak November - April 2 p.m. - 9 p.m. 3 p.m. - 7 p.m.

Winter Partial-Peak November - April 7 a.m. - 2 p.m.,9 p.m. - 11 p.m. NA

Winter Off-Peak November - April Midnight - 7 a.m.,11 p.m. - Midnight

Midnight - 3 p.m.,7 p.m. - Midnight

Current Months Weekdays Weekends/Holidays

Summer Peak June - September 4 p.m. - 9 p.m. 4 p.m. - 9 p.m.

Summer Partial-Peak June - September 3 p.m. - 4 p.m.,9 p.m. - Midnight

3 p.m. - 4 p.m.,9 p.m. - Midnight

Summer Off-Peak June - September Midnight - 3 p.m. Midnight - 3 p.m.

Winter Peak October - May 4 p.m. - 9 p.m. 4 p.m. - 9 p.m.

Winter Partial-Peak October - May 3 p.m. - 4 p.m.,9 p.m. - Midnight

3 p.m. - 4 p.m.,9 p.m. - Midnight

Winter Off-Peak October - May Midnight - 3 p.m. Midnight - 3 p.m.

(PG&E-3)

3-35

In this proceeding, PG&E recommends adjustments to the TOU 1

rate differentials for Schedule EV, effective January 1, 2022, but not for 2

Schedule EV2. 3

a. Schedule EV 4

In D.17-01-006, the Commission indicated that while solar 5

customers could be grandfathered on the current TOU periods (both 6

seasons and hours), the rates for those outdated legacy TOU periods 7

may be adjusted to reflect the changing underlying marginal costs 8

associated with those months and hours. This is provided, however, 9

that the adjusted, cost-based rates could not result in the partial-peak 10

rate exceeding the peak rate.45 11

The yellow and orange portions of Table 3-16 below show the 12

current Schedule EV POPP differentials compared to the updated 13

marginal costs developed by PG&E for this proceeding. As that table 14

shows, the current summer generation and distribution differentials 15

between peak and off-peak rates of 21.0 and 18.7 cents, respectively, 16

are now substantially higher than the corresponding marginal cost 17

differentials of 12.48 and 6.8 cents. To move the rates somewhat closer 18

to these much smaller marginal costs, PG&E is proposing to reduce the 19

peak versus off-peak price differentials for both generation and 20

distribution by 2.0 cents, as shown in the blue portion of Table 3-16. 21

A similar situation exists when comparing the current summer 22

generation and distribution differentials between part-peak and off-peak 23

rates (6.6 and 8.6 cents, respectively) to the corresponding marginal 24

cost differentials (of 1.72.5 and zero cents, respectively). PG&E is 25

proposing to reduce these two differentials by 2.0 cents as well, again to 26

bring TOU rate differentials somewhat more in line with the smaller 27

marginal cost differentials. 28

45 See D.17-06-001, p. 64, and footnote 48.

(PG&E-3)

3-36

TABLE 3-16 SCHEDULE EV RATE DIFFERENTIALS VS. FULL MARGINAL COST DIFFERENTIALS

($/KWH)

For winter, the current generation differentials between peak and 1

off-peak rates, and between part-peak and off-peak rates, are not far 2

from the corresponding marginal cost differentials. Here, PG&E 3

proposes simply to set the proposed differentials equal to the target 4

marginal cost differentials.46 However, the current distribution 5

differentials between peak and off-peak rates, and between part-peak 6

and off-peak rates, are greatly in excess of the corresponding marginal 7

cost differentials. So here, too, PG&E is proposing to reduce each of 8

those rate differentials by 2.0 cents to bring them somewhat closer to 9

the much lower marginal cost differentials (which are very close to zero). 10

b. Schedule EV2 11

In PG&E’s 2017 GRC Phase II proceeding, the 12

Commission-approved new EV TOU periods and rates that were part of 13

a settlement between PG&E and other parties, which subsequently 14

became the new Schedule EV2.47 That settlement provided that 15

46 Due to a mis-alignment of the legacy Schedule EV TOU periods with current marginal

costs, the marginal generation cost in the winter part-peak period is actually lower than in the winter off-peak period. PG&E proposes, however, to set the winter part-peak generation rate equal to the winter off -peak generation rate, so as to avoid possible customer confusion.

47 See D.18-08-013, OP 13.

Generation Distribution Total Generation Distribution Total Generation Distribution Total

Summer Peak vs. Off-Peak $0.210 $0.187 $0.397 $0.190 $0.167 $0.357 $0.124 $0.068 $0.192

Summer Part-Peak vs. Off-Peak $0.066 $0.086 $0.153 $0.046 $0.066 $0.113 $0.017 $0.000 $0.017

Winter Peak vs. Off-Peak $0.034 $0.199 $0.233 $0.024 $0.179 $0.203 $0.024 $0.001 $0.025

Winter Part-Peak vs. Off-Peak -$0.005 $0.092 $0.087 $0.000 $0.072 $0.072 $0.000 $0.000 $0.000

Schedule EVCurrent Rate Differentials Proposed Rate Differentials Full Marginal Cost Target Differentials

Generation Distribution Total Generation Distribution Total Generation Distribution Total

Summer Peak vs. Off-Peak $0.210 $0.187 $0.397 $0.190 $0.167 $0.357 $0.128 $0.068 $0.196

Summer Part-Peak vs. Off-Peak $0.066 $0.086 $0.153 $0.046 $0.066 $0.113 $0.025 $0.000 $0.025

Winter Peak vs. Off-Peak $0.034 $0.199 $0.233 $0.025 $0.179 $0.204 $0.025 $0.001 $0.026

Winter Part-Peak vs. Off-Peak -$0.005 $0.092 $0.087 $0.000 $0.072 $0.072 $0.000 $0.000 $0.000

Schedule EVCurrent Rate Differentials Proposed Rate Differentials Full Marginal Cost Target Differentials

(PG&E-3)

3-37

future changes to all EV2 TOU rates would be made on an 1

equal-cents-per-kWh basis until the rate design is re-evaluated in a 2

future rate proceeding that occurs no sooner than PG&E’s 2023 GRC 3

Phase II. Accordingly, as shown in Table 3-17, in this proceeding PG&E 4

is not proposing any changes to the EV2 TOU rate differentials from the 5

differentials agreed upon by the settling parties and approved by the 6

Commission in D.18-08-013. 7

TABLE 3-17 SCHEDULEV2 RATE DIFFERENTIALS VS. FULL MARGINAL COST DIFFERENTIALS

($/KWH)

6. Rules for Changing TOU Rates Between GRC Proceedings 8

After the TOU rates are set in this proceeding, PG&E proposes that all 9

subsequent changes to rates on residential TOU schedules, between this 10

2020 GRC Phase II and PG&E’s 2023 GRC Phase II, be calculated on an 11

equal-cents-per-kWh basis. Doing so will maintain the marginal cost-based 12

TOU rate differentials adopted in this proceeding.48 Furthermore, given 13

PG&E’s proposal for rate changes between GRCs for Schedule E-1 14

described in Section D.3. above, which will also be made on an 15

equal-cents per kWh basis, the baseline credits on PG&E’s tiered TOU rates 16

48 This is consistent with the rules for rate changes between GRCs approved by the

Commission in D.18-08-083 for PG&E’s 2027 GRC Phase II.

Generation Distribution Total Generation Distribution Total Generation Distribution Total

Summer Peak vs. Off-Peak $0.086 $0.227 $0.313 $0.086 $0.227 $0.313 $0.186 $0.099 $0.285

Summer Part-Peak vs. Off-Peak $0.041 $0.161 $0.202 $0.041 $0.161 $0.202 $0.053 $0.015 $0.069

Winter Peak vs. Off-Peak $0.036 $0.149 $0.185 $0.036 $0.149 $0.185 $0.044 $0.004 $0.047

Winter Part-Peak vs. Off-Peak $0.023 $0.145 $0.169 $0.023 $0.145 $0.169 $0.019 $0.001 $0.019

Current Rate Differentials Proposed Rate Differentials Full Marginal Cost Target Differentials Schedule EV2

Generation Distribution Total Generation Distribution Total Generation Distribution Total

Summer Peak vs. Off-Peak $0.086 $0.227 $0.313 $0.086 $0.227 $0.313 $0.192 $0.099 $0.291

Summer Part-Peak vs. Off-Peak $0.041 $0.161 $0.202 $0.041 $0.161 $0.202 $0.060 $0.015 $0.076

Winter Peak vs. Off-Peak $0.036 $0.149 $0.185 $0.036 $0.149 $0.185 $0.044 $0.004 $0.048

Winter Part-Peak vs. Off-Peak $0.023 $0.145 $0.169 $0.023 $0.145 $0.169 $0.018 $0.001 $0.018

Current Rate Differentials Proposed Rate Differentials Full Marginal Cost Target Differentials Schedule EV2

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(Schedules E-TOU-C and E-6) will remain unchanged when rates change.49 1

As described below in Sections F and G, residential customers on TOU 2

rates who qualify for either CARE or FERA would continue to receive 3

line-item discounts (35 percent for CARE, 18 percent for FERA) off their 4

calculated TOU schedule bills. 5

F. CARE Program 6

D.15-07-001 prescribed a glidepath for gradually reducing PG&E’s CARE 7

discount percentage to the top end of the statutory range of 30 to 35 percent.50 8

PG&E’s CARE discount percentage reached the final step in the glidepath on 9

March 1, 2020 when it was reduced from 35.5 to 35 percent.51 10

In Phase IIA of the 2018 RDW proceeding, PG&E proposed to simplify how 11

CARE rates are administered by eliminating its CARE rate schedules and 12

instead provide the CARE discount via a line-item percentage discount off the 13

customer’s corresponding non-CARE rate schedule. The Commission approved 14

PG&E’s line-item CARE discount in D.18-12-004 and PG&E subsequently filed 15

ALs 5547-E and 5638-E with tariff changes to implement the line-item 16

discount.52 As a result, PG&E eliminated Schedule EL-1 and all its other CARE 17

tariffs on March 1, 2020, and now provides CARE discounts as a partial line-item 18

discount via newly-approved Schedule D-CARE.53 19

49 The Baseline credits on PG&E’s two-tiered TOU rates E-TOU-C and E-6 are calculated

based on the E-1 rates, as a sales-weighted average of (a) the difference between the E-1 Tier 2 and Tier 1 rates and (b) the difference between the E-1 HUS Tier and Tier 1 rates. Since neither (a) nor (b) will change under PG&E’s proposal when rates are changed, the Baseline credit will remain the same so long as the sales weights do not change. However, if a rate change due to changing revenue requirements also involves a new sales forecast (for example, as typically occurs once per year, when the ERRA sales forecast is adopted), then the Baseline credit may change due to changing sales weights.

50 See Pub. Util. Code Section 739.1(c)(1). 51 See D.15-07-001, p. 236, and PG&E AL 4697-E (approved by Energy Division on

November 12, 2015), p. 2. 52 AL 5547-E was filed on May 22, 2019 and approved by Energy Division on June 13,

2019. AL 5638-E was filed on September 18, 2019 and approved by Energy Division on January 21, 2020.

53 Schedule D-CARE acts as a rider on the customer’s selected non-CARE schedule.

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As noted above, PG&E’s overall average effective CARE discount has, 1

since March 1, 2020, been set at 35. In this GRC Phase II proceeding, PG&E 2

proposes that the CARE discount percentage remain at its current 35 percent 3

level. 4

PG&E does recommend one change to the CARE discount, though, 5

pertaining to the DMBA. In proposing a line-item discount for CARE in 6

Phase IIA of the 2018 RDW, one of PG&E’s primary objectives was to make the 7

discount simple for customers to understand. Another objective was to be able 8

to implement the discounts via a single rider rate, Schedule D-CARE, and thus 9

eliminate a significant number of stand-alone CARE rate schedules. PG&E’s 10

vision was that a CARE household could easily see it was receiving a 35 percent 11

discount on the total bill if the bill were first calculated based on non-CARE rates 12

and then, at the end, reduced by a 35 percent line-item CARE discount. 13

However, in D.15-07-001, the Commission specified that the DMBA for 14

CARE customers be set at $5.54 The fact that this is a 50 percent discount on 15

that particular rate component compared to the $10 DMBA paid by non-CARE 16

customers complicates matters and makes it difficult to achieve the intended 17

benefit of a CARE bill that is simpler and easier to understand. This is because 18

a rate design which discounts the DMBA by more than 35 percent can only 19

achieve an overall average effective discount of 35 percent if the energy charges 20

are discounted at a percentage lower than 35 percent. Specifically, energy rates 21

need to be discounted at about 34.8 percent so that, in combination with a 22

50 percent discount on the DMBA, they yield a 35 percent overall average 23

effective discount.55 So, rather than being able to give CARE customers a 24

simple message that their bills are being discounted by 35 percent, PG&E 25

must instead explain that the discounts for most CARE customers is only 26

34.862 percent, in order for a small percentage of very low-usage customers to 27

receive discounts of up to 50 percent. 28

54 See D.15-07-001, p. 227, and Conclusion of Law (COL) 21. 55 This is just an estimate. The precise discount percentage for the energy charges is not

known as of the date this testimony is being filed. It depends on the 2020 forecasted billing determinants (in particular, kWh subject to the DMBA) and the residential revenue requirement that will be in place on March 1, 2020.

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D.15-07-001 did not permanently lock in a $5 DMBA, but rather allowed for 1

future changes via each utility’s GRC Phase II proceeding.56 Accordingly, in 2

this proceeding PG&E proposes that there no longer be a separate DMBA rate 3

for CARE customers. Instead, the CARE discount would be provided as a 4

35.0 percent line-item discount for all customers regardless of their usage 5

level.57 This would eliminate the variation in percentage bill discounts received 6

by customers with varying usage levels and allow for a much simpler customer 7

outreach message: “Every CARE customer, regardless of rate schedule or 8

usage, receives the identical 35 percent discount.” It would have minimal effects 9

on CARE customer bills, at most increasing a bill by $1.50 for a customer with 10

zero usage, while also resulting in bill decreases for the vast majority of 11

CARE customers. 12

G. FERA Program 13

PG&E currently provides an 18 percent discount to its residential customers 14

on the FERA program. This 18 percent level is specified by statute,58 and is 15

currently provided via Schedule E-FERA, which acts as rider on the customer’s 16

selected rate schedule. In this proceeding, PG&E is proposing just one change 17

to FERA rates, which mirrors PG&E’s CARE proposal in the previous section. 18

Currently, customers on Schedule E-FERA receive an 18 percent discount 19

relative to standard, non-low income rates, but also receive a 50 percent 20

discount on the DMBA rate component, if applicable (i.e., their DMBA is set at 21

the same $5 level as for CARE).59 This results in very low-usage customers 22

56 D.15-07-001, at p. 227, stated that:

[T]he minimum bill shall be set at $10 for non-CARE customers and $5 for CARE customers starting with the 2015 rate changes to be implemented under this decision. The future minimum bill...amounts shall be subject to review by the Commission and the parties through the IOU’s GRC Phase II applications.

57 Mathematically, this is equivalent to discounting each and every rate component, including the DMBA, by 35 percent. So, although there would no longer be any stand-alone CARE rate schedules, the effective DMBA for CARE customers would be $6.50.

58 See Pub. Util. Code Section 739.12(b). 59 See D.15-07-001, COL 21.

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subject to the DMBA receiving discounts in excess of 18 percent.60 Because of 1

that, the overall average FERA discount exceeds the 18 percent level codified in 2

the statute.61 3

To correct this and bring the overall average effective FERA discount to 4

18 percent, PG&E is proposing here to eliminate the $5 DMBA for FERA 5

customers and, instead, provide the FERA discount as a true 18 percent 6

line-item discount for all customers regardless of usage level.62 Like PG&E’s 7

CARE line-item discount proposal, this would eliminate the variation in 8

percentage bill discounts received by FERA customers with varying usage levels 9

and allow for a much simpler customer outreach message: “Every FERA 10

customer, regardless of rate schedule or usage, receives the identical 11

18 percent discount mandated by statute.” It, too, would have minimal effects on 12

FERA customer bills, at most increasing a bill by $3.20 (for a customer with 13

zero usage). 14

H. Medical Baseline Program 15

D.18-08-013 approved a settlement that included a number of reforms to 16

PG&E’s Medical Baseline Program to be implemented in 20202021: 17

End the 4-cent-per-kWh credit for non-CARE Medical Baseline customers 18

for usage exceeding 200 percent of baseline; 19

Change the methodology for calculating Tier 2 and Tier 3 usage for Medical 20

Baseline customers to the same methodology used for non-Medical 21

Baseline customers; and 22

For non-CARE Medical Baseline, apply an equal cents per kWh discount to 23

all usage by reducing the CIA by an amount equal to the Department of 24

Water Resources bond charge, currently approximately 0.5 cents per kWh. 25

60 In fact, a zero-usage FERA household currently pays the same $5 monthly bill as an

economically worse-off zero-usage CARE customer. 61 Pub. Util. Code Section 739.12(b) states: “The FERA program discount shall be an

18 percent line-item discount applied to an eligible customer’s bill calculated at the applicable rate for the billing period.”

62 Mathematically, this is equivalent to discounting each and every rate component, including the DMBA, by 18 percent, resulting in the effective DMBA for FERA customers being $8.20.

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In addition, in D.18-09-013 the CPUC approved an uncontested settlement 1

among PG&E and other parties specifying that Medical Baseline customers 2

served by CCAs will have their Power Charge Indifference Adjustment (PCIA) 3

exemption phased-out (or, as stated alternatively in the settlement, have their 4

PCIA charge phased in) over a 4-year period beginning as early as June 1, 5

2019.63 PG&E expects to begin this phase-in late 2021. 6

PG&E is here proposing just one further change to Medical Baseline beyond 7

those approved by D.18-08-013. Specifically, similar to its proposals for CARE 8

and FERA customers, PG&E is proposing that Medical Baseline customers also 9

be subject to a $10 DMBA instead of the current $5 amount. This will facilitate 10

uniformity for all of PG&E’s residential schedules. All customers, including 11

CARE, FERA, and Medical Baseline, will be subject to a $10 DMBA. CARE and 12

FERA customers will receive their discounts via line-item discounts and Medical 13

Baseline customers will receive their discounts by receiving additional baseline 14

allocations and thus being able to consume additional kWh at the lower Tier 1 15

rate. This proposed change is unlikely to affect many Medical Baseline 16

customers, since the DMBA only affects the bills of very low users and Medical 17

Baseline customers typically are high users. Indeed, the whole rationale for 18

providing such customers with additional baseline amounts is to mitigate the 19

high bills they would otherwise face due to their medical needs causing their 20

usage to increase into the upper tiers. 21

I. SmartRate Program 22

PG&E’s SmartRate Program is designed to provide load relief during 23

selected periods, typically on hot summer days when costs are particularly high. 24

It is a voluntary opt-in program for residential customers who see very high 25

prices during a limited number of event hours, and thus have strong incentives 26

to reduce load during those hours. Participating customers benefit from lower 27

prices during non-event hours. The SmartRate Program is implemented via 28

Schedule E-RSMART, which acts as a rider rate in conjunction with the 29

customer’s selected rate schedule. 30

In Phase IIB of the 2018 RDW, PG&E proposed a number of changes to the 31

rate design of its SmartRate Program, including moving the event hours to later 32

63 D.18-09-013, p. 7.

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in the day (from 2-7 p.m. to 5-8 p.m.) and modifying the way in which credits and 1

charges are assigned to SmartRate customers. These changes were approved 2

by the Commission in D.18-12-004, and PG&E proposes no further 3

changes here. 4

J. Study on Feasibility of Remote Dispatch of Residential Battery Storage 5

In D.18-08-013, deciding PG&E’s 2017 GRC Phase II (D.18-08-013), the 6

Commission adopted the Settlement Agreement on Residential Rate Design, 7

which requires PG&E to analyze the feasibility of programs for remote dispatch 8

of residential battery storage: 9

Prior to the next Phase II GRC, PG&E will analyze the feasibility of providing 10 a program or programs for residential customers with battery storage that 11 requires a minimum amount of remote dispatch of the storage unit at the 12 direction of PG&E or the Independent System Operator. PG&E may 13 conduct this analysis either for inclusion in the next Phase II or as part of 14 another Commission proceeding. The analysis shall consider technical, 15 economic, and ratemaking challenges along with identifying potential 16 benefits to the grid, non-participating customers, and California’s 17 greenhouse gas goals. PG&E shall consult with interested stakeholders in 18 conjunction with its analysis.64 19

Pursuant to this agreement, PG&E conducted the study based on multiple 20

components, including PG&E’s participation in the SGIP Greenhouse Gas 21

(GHG) Signal Working Group and two Electric Program Investment Charge 22

(EPIC) projects. The GHG Signal Working Group developed recommendations 23

for the content and delivery of a GHG signal (e.g., dynamic information on 24

marginal GHG impacts of load). The study also considered two EPIC Projects 25

that focused respectively on the use of customer-sited storage to reduce peak 26

load and absorb excess DER generation and on producing proof of concept 27

software to control these remote resources. The results of this study are 28

summarized in Attachment A to this chapter, “Feasibility of Remote Dispatch of 29

Residential Energy Storage.” 30

K. Master Meter Discounts 31

This section presents PG&E’s electric master meter discount proposals for 32

Electric Multifamily Service (Schedule ES) and Electric MHP Service 33

64 D.18-08-013, OP 13, relating to January 24, 2018 Motion for Adoption of Residential

Rate Design Supplemental Settlement Agreement.

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(Schedule ET).65 Under both of these rate schedules, electricity is delivered to 1

a single master meter at a residential development. Under Schedule ET, the 2

electricity is then delivered through a private sub-metered distribution system to 3

individual tenants within the master-metered MHPs. Under Schedule ES, 4

electricity is delivered to multi-family residential accommodations through 5

one large “bank” of clustered sub-meters. PG&E’s end-use customers on the 6

master meter schedules are the owners of the master-metered MHP or other 7

master-metered multi-family residential developments, such as apartment 8

buildings or apartment complexes. The owners taking service from PG&E under 9

these master meter rate schedules receive a discount to compensate them for 10

utility avoided costs because, although the utility directly delivers electricity to 11

the master meters, it avoids any costs related to delivering electricity to the 12

tenants’ sub-meters. These rate schedules have been closed to new customers 13

since January 1, 1997. 14

65 This 2014 GRC Phase II Application includes only PG&E’s electric master meter

proposals. Consistent with a prior Commission ruling, PG&E will continue to submit its gas master meter testimony in its BCAP. (See January 10, 2005 Administrative Law Judge Ruling Granting Western Manufactured Housing Communities Association (WMA) Motion to Consider Gas Master Meter Discount Issues in A.04-07-044 and Modifying Scoping Memo in A.04-07-044.)

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The master meter discount methodology proposed in this application follows 1

the methodology as prescribed in D.18-08-013, D11-12-053, D.04-04-043, and 2

D.04-11-033.66 The next master meter discounts were set in D.15-08-005, 3

PG&E’s 2014 GRC Phase II, which adopted an all-party settlement. The current 4

master meter discounts were set in D.18-08-013, in PG&E’s 2017 GRC Phase II. 5

As discussed below, the WMA contested many aspects of the master meter 6

discounts proposed by PG&E, on many of the same grounds the Commission 7

had already rejected in D.11-12-053. However, as discussed in detail below, 8

D.18-08-013 upheld and reaffirmed the Commission’s disposition of those 9

contested master meter discount issues.67 10

PG&E’s proposed rates under the methodology adopted in D.18-08-013 are 11

a net discount of $2.0407 for Schedule ET, and a net discount of $1.1217 for 12

Schedule ES, per space per month. 13

1. Marginal Cost Master Meter Discount Methodology 14

In the 2003 GRC Phase II, PG&E proposed a marginal cost-based 15

approach for calculating the master meter discount, as opposed to the 16

sampling method presented by PG&E in previous GRCs.68 Discounts 17

calculated using this method were adopted in the settlement approved in the 18

decision for that proceeding.69 This same methodology was again adopted 19

in D.07-09-004 for PG&E’s 2007 GRC. In PG&E’s 2011 GRC Phase II, the 20

Company performed a thorough review of its master meter discount 21

methodology and carefully evaluated proposals presented by The Utility 22

Reform Network (TURN) and WMA. In response to these proposals, PG&E 23

further refined its methodology, with parties agreeing to some, but not all of 24

PG&E’s proposals. PG&E reached a settlement for the Schedule ES master 25

66 D.11-12-053, pp. 36-53. The WMA timely filed a Petition to Modify and Application for

Rehearing of Decision 11-12-053, both of which the CPUC denied. (See D.12-10-004 and D.12-08-046, respectively.) On September 21, 2012, WMA timely f iled with the Court a Petition for Writ of Review. The CPUC, as well as TURN and PG&E, all opposed WMA’s Petition, which was denied by the District Court of Appeal of the State of California in and for the First Appellate District, Division Three (No. A136617).

67 D.18-08-013, pp. 2, 114, 116, and 139. 68 2003 GRC Phase II, A.04-06-024, Exhibit (PG&E-10), Chapter 2B, “Residential Rates:

Electric Master Meter Discounts.” 69 D.05-11-005, p. 8; Appendix B, pp. 26-28.

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meter discount in its 2011 GRC Phase II that was approved by the 1

Commission in D.11-12-053. No settlement could be reached, however, for 2

the master meter MHP discount in Schedule ET, and the methodology was 3

fully litigated. In D.11-12-053, the Commission adopted PG&E’s MHP 4

master meter discount methodology, which was consistent with the 5

guidance provided in D.04-04-043 and D.04-11-033.70 6

In reaching its decision on MHP master meter methodology in PG&E’s 7

2011 GRC Phase II, the Commission resolved several highly contested 8

issues that had been the subject of debate for some time. The CPUC 9

decided: (1) to include replacement costs through application of the Real 10

Economic Carrying Cost (RECC) to new connection equipment costs; (2) to 11

exclude any Equal Percentage of Marginal Cost factors; (3) to consider new 12

connection costs to be equal to the costs capped by PG&E’s line extension 13

allowances under Rule 15 and 16 under the rental method; and (4) that 14

PG&E’s multi-family residential costs are a reasonable proxy for the average 15

avoided costs to directly serve tenants in master-metered MHPs. In this 16

proceeding, PG&E proposes to continue using that same methodology 17

consistent with what the CPUC adopted in D.11-12-053. 18

Similarly, in D.18-08-013, in Section 7.3, the Commission resolved and 19

expressly rejected disputed issues related to various WMA allegations that: 20

(1) the master meter discount failed to cover sub-metering system operating 21

costs; (2) line-extension allowances should be used as the basis for master 22

meter discounts; (3) several Schedule ET avoided cost and DBA dataset 23

inputs or assumptions should be changed or recalculated; (4) Schedule ET 24

should be its own separate revenue allocation class; (5) excavation 25

70 The 2004 decisions—D.04-04-043 and D.04-11-033—were the decisions arising from

PG&E’s GRC Phase I and Phase II, respectively, of the MHP Sub-Metering Discount R.03-03-017/Investigation 03-03-018. These 2004 decisions identified categories of costs avoided by electric and natural gas utilities when MHP tenants are served by a master meter owner. Specifically, D.04-04-043 “identified the categories of costs the electric and natural gas utilities incur when directly serving MHP tenants that are avoided by the utilities when the MHP is served through a distribution system owned and operated by the MHP owner.” (See D.04-11-033, p. 2, citing D.04-04-043.) These 2004 decisions allowed utilities to use a marginal cost methodology for master meter discount calculations in addition to the prior existing method using a statistically valid random sample of directly served MHPs in a utility’s service area.

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and replacement costs should be explicitly included in the master meter 1

discount; and (6) Schedule ET Special Condition 9 should be updated. 2

In this proceeding, PG&E proposes to continue using the same 3

methodology adopted by the CPUC in D.18-08-013. 4

The basis of this methodology can be described by the formula below: 5

(master meter discount) = (base discount) – (diversity benefit adjustment) 6

+ (line loss adjustment) 7

The base discount represents the costs of transformers, service 8

conductors, service drops, and meters that PG&E avoids in a master meter 9

arrangement. The amount of the base discount is different for ET and ES. 10

PG&E’s 2020 GRC proposed monthly base discount per residential unit is 11

$3.8487 for Schedule ET and $3.5257 for Schedule ES. The reason for this 12

is that a master meter arrangement (as opposed to an arrangement in which 13

PG&E serves each individual dwelling) results in different cost savings for 14

PG&E, depending on whether a master meter is used for an MHP or other 15

type of multi-family dwelling. The list below summarizes the avoided costs 16

that are different between MHP (ET) and other multi-family dwellings (ES). 17

Avoided costs not listed are the same across the two schedules: 18

1. Transformer equipment costs; 19

2. Service equipment costs; 20

3. Transformer operations and maintenance costs; 21

4. Service operations and maintenance costs; 22

5. Secondary distribution capacity costs; 23

6. Line loss costs; and 24

7. Average number of residential units. 25

For Items 1 through 6 in the list above, PG&E does avoid costs under 26

a master meter arrangement for MHP’s (ET), but avoids no costs in a 27

master meter arrangement for ES (multi-family). PG&E avoids costs for 28

MHP’s, but not multi-family dwellings, because a MHP owner must construct 29

transformers and services to extend electric service from the master meter 30

to the sub-meters, thus displacing PG&E’s cost. However, in a multi-family 31

dwelling that would be eligible for Schedule ES, all the sub-meters are 32

clustered in one large “bank” of meters. This means that the owner of the 33

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multi-family dwelling does not construct transformers and services to extend 1

electric distribution from the master meter to the sub-meters; rather, PG&E 2

does. Therefore, PG&E saves no transformer and service costs in a master 3

meter arrangement for multi-family dwellings. Item 7 (average number of 4

residential units) is included here because, on average, MHP’s and other 5

multi-family dwellings have different numbers of dwellings. PG&E’s 2020 6

GRC proposed monthly base discount per residential unit is $3.8487 for 7

Schedule ET and $3.5257 for Schedule ES. 8

The line loss adjustment increases the amount of the discount for MHP 9

(ET) owners. This adjustment accounts for the fact that the MHP owners 10

must purchase more electricity at the master meter than the total electricity 11

that the tenants demand at their individual sub-meters. Additional power is 12

needed because some power is lost in the distribution system between the 13

master meter and the sub-meters. 14

The line loss adjustment is calculated by multiplying the Average Loss 15

per residential unit by the Weighted Average Price per kWh. The Average 16

Loss is equal to the Average Usage per residential unit multiplied by (one 17

minus the Capacity Loss Adjustment Factor). The Capacity Loss 18

Adjustment Factor is the proportion of energy that is lost due to line losses 19

between the master meter and the sub-meters. The Weighted Average 20

Price per kWh is calculated by multiplying the per kWh price in each tier by 21

the average monthly usage in that tier, and then dividing by the sum of the 22

average monthly usage in all tiers. 23

For example, suppose that the sub-metered tenants wish to purchase a 24

total of 95 kWh of electricity from PG&E. This means that the owner must 25

purchase more than 95 kWh to serve these customers, because some 26

electricity is lost in transfer between the master meter and the tenant 27

meters. If line losses are 5 percent, the owner will purchase 100 kWh, but 28

will only transmit 100 – (100*0.05) = 95 kWh to the tenants. The line loss 29

adjustment compensates those owners for the lost 5 kWh. PG&E’s 30

proposed line loss adjustment for the 2020 GRC is $2.35 per month per 31

residential unit. 32

The diversity benefit adjustment (DBA) decreases the master meter 33

discount. The reason for this decrease is that the MHP owner receives a full 34

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baseline allowance for each of the sub-metered dwellings, even though 1

some dwellings use less than the baseline allowance. If the DBA did not 2

exist, the owner would face an artificially low rate for electricity because his 3

baseline quantity would be too high, and as a result an excessive amount of 4

usage would fall into the lower tiers. The diversity benefit adjustment will be 5

discussed in detail in the next section. 6

2. Diversity Benefit Adjustment 7

a. Introduction 8

The Commission has repeatedly endorsed and adopted the master 9

metered baseline DBA on a conceptual basis, at historical DBA values 10

that reflected the residential tier structure in place at the time. In the 11

discussion below, PG&E explains the impact that a residential fixed 12

monthly customer charge would have on the DBA and offers analysis of 13

three alternative approaches that account for CARE participation in 14

different ways. Ultimately, PG&E recommends adoption of the SCE 15

CARE Strata method, which results in a proposed DBA value for PG&E 16

of $4.14 per space per tenant. Since the DBA is merely illustrative, and 17

must be re-calculated at the time of implementation, PG&E’s proposed 18

DBA value was not rerun or updated for this 2020 GRC Phase II 19

Update filing. 20

b. Background 21

The Residential Baseline DBA for MHP service was first adopted by 22

the Commission for PG&E in 1986, at a level of $3.00 per space per 23

month for gas service and $1.59 per space per month for electric 24

service.71 The Commission stated as follows: 25

A diversity benefit exists when a master metered customer has 26 more sales billed at baseline rates and less at non-baseline rates 27 than are actually used by his sub-metered customers. PG&E 28 deserves credit in addressing an inequity in the billing of 29 sub-metered mobile home parks. PG&E has clearly 30 demonstrated that a sub-metered mobile home park benefits 31

71 D.86-12-091, pp. 35-36, in PG&E’s 1986 Energy Cost Adjustment Clause proceeding.

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when a sub-metered customer consumes less than his full 1 baseline allowance while another customer consumes more.72 2

The Commission later also defined the DBA as follows: 3

The diversity benefit adjustment reduces the discount paid to the 4 MHP owner to account for the fact that while the MHP owner 5 receives a full baseline allowance for each space, some tenants 6 use less than the baseline allowance, and some spaces may 7 be vacant.73 8

In its 2003 GRC Phase II proceeding, PG&E proposed to increase 9

the Schedule ET DBA to $3.48 per space per month to reflect the new 10

five-tiered residential rate structure implemented June 1, 2001. 11

However, in the 2003 GRC Phase II settlement, the DBA value of 12

$0.56 per space per month was not changed, and PG&E agreed to work 13

with TURN and the WMA to conduct a new study to calculate the 14

Schedule ET DBA. 15

This study was still in progress as of the filing date for PG&E’s 2007 16

GRC Phase II Application. In the 2007 GRC Phase II settlement 17

agreement, PG&E agreed to submit the study by August 1, 2007. After 18

submitting the study, PG&E agreed to certain refinements proposed by 19

WMA. The resulting DBA was $4.24 per space per month, but was not 20

implemented in the 2007 GRC Phase II due to the delay in submitting 21

the study. 22

The agreed methodology for the Schedule ET DBA relies on a 23

sample of approximately 206 directly metered electric MHP to represent 24

a master metered population of approximately 1,350 master metered 25

electric MHP served on Schedule ET. The sample of 206 MHP 26

consists of tenant units and common area accounts individually metered 27

directly by PG&E, generally served on residential rate Schedules E-1 28

and EL-1, for Non-CARE and CARE tenants respectively. This directly 29

metered sample is stratified by: (1) climate zone (four climate zones); 30

(2) average tenant usage (under or over 400 kWh per tenant per 31

month); and (3) size of park (under or over 50 tenant spaces), to 32

72 D.86-12-091, pp. 34-35, emphasis added. 73 D.04-11-033, p. 10, footnote 6.

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statistically project from the sample an estimated average monthly 1

diversity benefit for the overall master metered Schedule ET population. 2

c. 2017 GRC Phase II Proposed DBA 3

In PG&E’s 2017 GRC Phase II proceeding, PG&E proposed an 4

updated Schedule ET DBA value of $5.73 per space per month. This 5

proposal was based on all previously adopted DBA models and 6

methods, with the exception that PG&E included a new proposal that the 7

diversity benefits of the residential delivery minimum bill be included in 8

the DBA quantification. This is important because the park operator can 9

collect one minimum bill from each tenant with very low usage, but at 10

the central master meter level, PG&E can impose only one minimum bill. 11

In addition, in PG&E’s 2017 GRC Phase II rebuttal testimony, PG&E 12

noted that CARE participation in the directly-metered sample was just 13

under 60 percent, and just above 30 percent in the master-metered 14

population, based on updated 2014 and 2015 sample and master 15

metered population kWh usage per tenant and CARE status. As a 16

result, the sample, with a much higher CARE saturation, will have a 17

much lower DBA than the population. However, PG&E had failed to 18

normalize for this important discrepancy between the sample and the 19

population in all previously adopted Schedule ET DBA values for 20

PG&E.74 In its 2017 GRC Phase II rebuttal testimony, PG&E therefore 21

proposed that 45 percent of CARE tenants in the sample be treated as 22

Non-CARE to match the level of CARE participation among the 23

master-metered population. 24

In D.18-08-013, the Commission adopted PG&E’s originally 25

proposed DBA after a $0.36 adjustment proposed by WMA, including 26

the impact of the new minimum bill. PG&E’s 2017 GRC Phase II 27

D.18-08-018 was implemented with respect to the Schedule ET net 28

master meter discount on March 1, 2019, in AL 5429-E, at a value of net 29

master meter discount = Base + LLA – DBA, or $1.88 = $5.08 + 30

$2.18 - $5.37. 31

74 The fact that PG&E had never before accounted for the impacts of the residential

minimum bill, or the higher CARE saturation in the sample, each benefitted WMA, during all applicable periods from 1986 to the present.

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Although the Commission rejected PG&E’s CARE Participation 1

normalization proposal in D.18-08-013, PG&E believes the Commission 2

did so primarily because the increased value of the DBA under the 3

CARE Participation normalization method would have established a net 4

negative Schedule ET master meter discount. However, for SCE, the 5

Commission had adopted a similar methodology to account for 6

differences in CARE participation rates between the sample versus the 7

population, in which SCE replaced the strata for the size of the park by a 8

CARE participation rate stratum, of under or over 40 percent.75 In 9

addition, in PG&E’s 2018 GCAP, the Commission adopted PG&E’s 10

CARE normalization approach for the purpose of setting the DBA for 11

master metered gas MHP.76 12

PG&E has investigated how the resulting proposed Schedule ET 13

DBA would vary based on these three alternate approaches. First, 14

under PG&E’s old method, using no CARE adjustment as applied to 15

current updated recorded usage data for 2017 and 2018 and proposed 16

rates and baseline quantities, the Schedule ET DBA would be $4.20 per 17

space per month. Second, the Schedule ET DBA would be $4.38 under 18

PG&E’s CARE Participation normalization approach. Third, the 19

Schedule ET DBA would be $4.14 under the SCE CARE Strata 20

approach.77 PG&E proposes that the Commission adopt a 21

Schedule ET DBA of $4.14 per space per month based on the SCE 22

CARE Strata method, adopted in D.13-03-031 and D.16-03-030. 23

75 See SCE’s 2012 and 2016 GRC Phase II rate design testimony, Appendix G, footnote 6

of 2012 proceeding, and footnote 86 of its 2016 GRC Phase II. SCE’s CARE Strata method was adopted in D.13-03-031, pp. 11-13, and D.16-03-030, p. 20.

76 D.19-10-036, pp. 52-59. In both PG&E’s 2017 GRC Phase II proceeding and 2018 GCAP proceeding, WMA alleged that the DBA was invalid and should be eliminated or set to zero. This position was rejected in both D.18-08-013 (p. 140) and D.19-09-036 (pp. 54, 56, and 59).

77 While SCE used an under and over strata cutoff of 40 percent CARE participation for the CARE strata, PG&E used a 70 percent participation rate for the CARE strata cut-off. The 70 percent level provided larger sample sizes relative to the population than the 40 percent level, and also provided slightly lower standard deviations.

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d. PG&E’s Proposed 2020 GRC Phase II Diversity Benefit Adjustment 1

For this 2020 GRC Phase II proceeding, as noted above, PG&E’s 2

primary proposal is to adopt the Schedule ET DBA value of $4.14, 3

based on the SCE Care Strata method. Accordingly, PG&E has once 4

again updated the prior Schedule ET DBA study, using 2017 and 2018 5

sample and population78 kWh usage per tenant, as well as the data 6

base and all analytical methods authorized and adopted by the CPUC in 7

prior GRC Phase II proceedings. However, PG&E has now stratified the 8

sample by replacing the prior size of MHP strata with a strata for CARE 9

participation, as under 70 percent participation versus over 70 percent 10

participation. 11

More specifically, for this 2020 GRC Phase II DBA proposal, the 12

sample of 206 directly served MHPs comprised of some 13,400 tenant 13

units has been rerun based on updated 2017 and 2018 calendar year 14

recorded usage. As before, the model has also been updated to re-tier 15

all recorded usage at the proposed 2020 GRC Phase II Schedule E-1 16

and Schedule EL-1 CARE rates79 and baseline quantities. In addition, 17

PG&E deleted approximately ten directly metered solar NEM tenants 18

from the sample, as NEM customers do not occur in the master-metered 19

population and have abnormal recorded kWh usage levels. 20

78 It should be noted that the master metered Schedule ET MHP population may be

slightly decreasing over time as a result of the Commission mandated 3-year statewide pilot program originating from D.14-03-021 to convert 10 percent of MHP spaces in California from master meter service to direct utility service. Under this program, PG&E converted 13 Schedule ET master-metered parks in 2016, 46 parks in 2017, and 14 parks in 2018, to direct utility service. This MHP conversion program is discussed in PG&E’s 2020 GRC Phase I testimony, Exhibit (PG&E-12), Chapter 13, “Mobile Home Park Utility Upgrade Program,” revised June 18, 2019, and in periodic progress reports, such as PG&E’s Mobile Home Park Utility Upgrade Program CPUC 2018 Report, submitted February 1, 2019.

79 In AL 5547-E, effective October 1, 2019, the Commission approved the elimination of all separate CARE tariffs, replaced by a new rider Schedule D-CARE tariff to provide a line-item CARE discount as a simple 35.5 percent reduction to the Non-CARE bill. In this 2020 GRC Phase II proceeding, the 35.5 percent reduction is revised to 35.0 percent to comply with Commission adopted requirements expected to become effective March 1, 2020. However, PG&E subsequently filed superseding AL 5638-E, to be effective March 1, 2020, rather than October 1, 2019. AL 5638-E was approved by Energy Division on January 21, 2020, effective March 1, 2020.

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The resulting MHP DBAs proposed by PG&E for this 2020 GRC 1

Phase II proceeding based on the adopted SCE CARE Strata approach 2

are $4.14 per space per month for Schedule ET and $2.40 for 3

Schedule ES.80 The Schedule ET proposed value has decreased 4

compared to the currently-adopted $5.37 value per D.18-08-013. PG&E 5

attributes the decrease to: reductions in proposed baseline quantities; 6

changes in tenant usage in 2017 and 2018, compared to 2014 and 7

2015; the residential Delivery Only Minimum Bill; use of the SCE CARE 8

Strata approach; and tier flattening that will occur on Schedule E-1, 9

compared to the 2017 GRC Phase II proceeding. 10

e. Impact of a Residential Fixed Monthly Charge on the DBA 11

The 2018 RDW (A.17-12-011) is a statewide proceeding on a 12

variety of measures related to implementation of default residential TOU 13

and other residential rate design issues addressed in D.15-07-001 in 14

RROIR 12-06-013. One of the issues under consideration in 15

A.17-12-011 is the possible implementation of a residential fixed 16

monthly customer charge. While D.20-03-003 rejected the 17

establishment of a residential fixed monthly customer charge, it allowed 18

utilities to file a new application to continue to pursue such a charge. 19

The impact of such a fixed monthly customer charge on the DBA has 20

been the subject of a previous Residential Rate Design Settlement in 21

PG&E’s 2014 GRC Phase II proceeding, as adopted in D.15-08-005, 22

where residential settlement Part III.A.1.b. held as follows: 23

b. Contingency for a Potential Future Monthly Service Fee 24

The MMHP Settling Parties agree it is reasonable to adjust the 25 Schedule ET billing method should the Commission adopt a Monthly 26 Service Fee for residential customers on rate Schedules E-1 27 and EL-1 prior to the effective date of the rate change implementing 28 the Commission’s decision in PG&E’s next GRC Phase II 29 proceeding. A Monthly Service Fee, if adopted prior to 30 implementation of a decision in PG&E’s next GRC Phase II 31

80 PG&E has calculated the ET DBA value under only the new Schedule E-1 4-month

summer residential baseline seasonal structure that took effect October 1, 2019. This 2020 GRC Phase II proceeding maintains the 4-month residential summer baseline structure.

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proceeding, will be added to the Schedule ET master meter bill 1 as follows: 2

Schedule ET Master Meter Bill Monthly Service Fee equals: One central master meter Monthly Service Fee* plus (non-CARE Monthly Service Fee multiplied by number of non-CARE tenant units) plus (CARE Monthly Service Fee multiplied by number of CARE tenant units). - - - - - *The one central master meter Monthly Service Fee = The CARE Monthly Service Fee if the park is on Schedule ETL, or The non-CARE Monthly Service Fee if the park is on Schedule ET.

For Schedule ES, similar 2014 GRC Phase II Residential Settlement 3

terms in Part III.A.2.b were agreed to as follows: 4

b. Contingency for a Potential Future Monthly Service Fee 5

The MMHP Settling Parties also agree that it is reasonable to adjust 6 the Schedule ES billing method should the Commission adopt a 7 Monthly Service Fee for residential rate Schedules E-1 and EL-1 8 prior to the effective date of the rate change implementing the 9 Commission’s decision in its next GRC Phase II proceeding. The 10 formula for incorporating a Monthly Service Fee into the 11 Schedule ES billing method is the same as for the Schedule ET 12 billing method described above.81 13

For this 2020 GRC Phase II proceeding, PG&E proposes that the 14

methodology outlined above from PG&E’s 2014 GRC Phase II 15

proceeding be implemented as appropriate. Should a Minimum Bill be 16

adopted in the 2018 RDW, PG&E’s DBA analysis already incorporates 17

the impact of the Delivery Only Minimum Bill. However, should a 18

residential fixed monthly customer charge be adopted in 2018 RDW 19

Phase III, the DBA analysis would be affected in two ways. First, if a 20

fixed customer charge is implemented, PG&E would expect to 21

discontinue the Delivery Only Minimum Bill. Second, the 22

implementation of a fixed customer charge would facilitate a 23

commensurate reduction in the residential tiered energy charges. 24

Under this fixed customer charge scenario, PG&E would need to 25

rerun its Schedule ET DBA analysis without the Delivery Only Minimum 26

Bill, and under the energy charges associated with a fixed customer 27

81 D.15-08-005, p. 10, Supplemental Residential Rate Design Settlement Agreement in

PG&E’s A.13-04-012, pp. v to ix.

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charge. If the fixed customer charge requires a commensurate 1

reduction only in the Tier 1 rate or price, consistent with prior 2

Commission treatment of tier ratios under a composite Tier 1 rate,82 the 3

diversity benefit magnitude may increase since the absolute tier 4

difference in cents per kWh is a key driver of the magnitude of the 5

Schedule ET DBA. If the fixed customer charge reduction were applied 6

to all volumetric tiered rates (not just Tier 1), the impact on the 7

Schedule ET DBA would be less than under the composite tier ratio 8

approach. In any event, PG&E would propose to rerun its DBA upon 9

2020 GRC Phase II implementation, at then effective residential and 10

other applicable rates. 11

f. DBA Conclusion 12

The Schedule ET diversity benefit study submitted in Exhibit 13

(PG&E-3) was based on the mutually-agreed sample of 206 electric 14

MHPs developed in 2007 where all tenant spaces and common area 15

accounts are directly individually metered by PG&E. PG&E 16

recommends that the Commission adopt SCE’s CARE Strata method, 17

rather than PG&E’s CARE normalization method, to set an adopted 18

value of $4.14 for the Schedule ET DBA based on PG&E data from 19

2017 and 2018 usage by tenants in the sample and in the ET 20

population. PG&E proposes to continue to set the Schedule ES DBA at 21

a ratio based on values calculated from random samples of MHPs and 22

multi-family apartment buildings in the 2003 GRC Phase II, which was 23

the basis for the 58 percent ratio adopted in D.11-12-053, D.15-08-005, 24

and D.18-08-013. Those prior 2003 GRC Phase II proposed values 25

were $3.48 per space for Schedule ET and $2.01 for Schedule ES.83 26

Applying this 58 percent ratio to the proposed Schedule ET DBA 27

of $4.14 produces a proposed Schedule ES DBA of $2.40 per space per 28

month. These proposed values for the Schedule ES and ET DBAs are 29

82 The composite Tier 1 rate is given by the sum of Tier 1 energy charge revenues, plus

applicable minimum bill revenues, plus applicable customer charge revenues, all divided by the sum of Tier 1 kWh usage and kWh usage associated with minimum bills.

83 The adopted 58 percent figure equals $2.01 divided by $3.48.

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reflected below in the net master meter discounts proposed in 1

Table 4-20. 2

These proposed DBA values are illustrative only and will be updated 3

upon implementation after a final decision in this 2020 GRC Phase II 4

proceeding based upon the rates and revenue requirements then in 5

effect.84 PG&E proposes that the DBA be set initially, and then 6

subsequently remain unchanged throughout the 3-year 2020 GRC 7

Phase II cycle, as has typically been done in the past. 8

3. Proposed Master Meter Discounts 9

Table 3-7 shows the present and proposed master meter discounts, 10

including PG&E’s resulting proposed base discounts, diversity benefits and 11

LLA.85 PG&E’s proposed base master meter discounts are summarized in 12

Table 3-18 for Schedules ET and ES. 13

TABLE 3-18 PRESENT AND PROPOSED ELECTRIC MASTER METER DISCOUNTS

(PER MONTH, PER UNIT)

Line No. Rate Schedule

Current Discount(a) Proposed 2020 Test Year Discount

Net Discount

Daily Equivalent

Base Discount

Diversity Benef it (-)

Adjustment

Line Loss (+)

Adjustment Net

Discount Daily

Equivalent

1 ET – Mobilehome Park Service

$1.88 $0.06181 $3.8487 $4.14 $2.35 $2.0407 0.0671506813

2 ES – Multifamily Service

$0.95 $0.03115 $3.5257 $2.40 – $1.1217 0.0368403847

_______________ (a) Electric Master Meter Discount Rate in effect October 1, 2019.

84 See discussion in D.11-12-053, mimeo, p. 41, as well as COL 12, and OP 13. 85 The LLA adds to the base discount to compensate the master meter customer for

usage at the master meter that is lost when distributed to the tenant spaces.

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TABLE 3-19 SCHEDULE ET – MASTER METER DISCOUNTS

Line No. Schedule ET Master Meter Discount

Costs for Tenant Meter

Costs for Master Meter(a)

1 Transformer $395.62378.73

$22,845.82714.54

2 Service 367.03334.85

27,026.5524,081.86

3 Meter 180.17182.64

1,753.08751.75

4 Transformer/Service/Meter (TSM) Equip. Cost 942.82896.22

51,625.4548,548.16

5 RECC 6.78% 6.78%

6 Annualized Connection Equipment Cost — Finance, Tax, Ins. & Depr.

$63.9360.77 $3,500.44291.78

7 Test Year Secondary Dist. ($/kilowatt-year (kW-Yr)) $2.2425 8 Test Year Ongoing Costs Per Residential Unit 9 Meter Services $11.30 $25.7718.46 10 Transformer Maintenance 0.7168 40.9773 11 Service Maintenance 2.3313 171.76153.05 12 Meter Reading 4.85 8.429.13 13 Billing & Payments 15.43 18.7713.46 14 Credit & Collections and Account Setup 3.16 7.193.44

15 Total Ongoing Costs Per Residential Unit $37.8056 $272.87238.26 16 Total Connection Cost $103.97100.

58 $3,773.31530.

05 17 Average Number of Residential Units 65 18 Master Meter Connection Cost Per Residential Unit $58.0554.31 19 Net Marginal Connection Cost Per Residential Unit $45.9246.27 20 Uncollectibles Factor 0.32530% 21 Uncollectibles 0.15

22 Net Base Discount Per Residential Unit — Annual $46.0742 23 Base Master Meter Discount Per Residential Unit —

Monthly $3.8487

24 Diversity Benefit Adjustment (Illustrative) 4.14 25 Line Loss Adjustment 2.35

26 Net Discount (Monthly) (Illustrative) $2.0407 27 Net Discount (Daily) (Illustrative) $0.06715068

13

_______________ (a) Master Meter costs uses Medium Light and Power (ML&P)-S proxy meter for connection;

Small Light and Power (SL&P) proxy meter for ongoing costs except transformer and service maintenance; transformer and service maintenance calculated for ML&P proxy connection.

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TABLE 3-20 SCHEDULE ES – MASTER METER DISCOUNTS

Line No. Schedule ES Master Meter Discount

Costs for Tenant Meter

Costs for Master Meter(a)

1 Transformer – – 2 Service – – 3 Meter $180.17182.6

4 $1,753.08751.7

5 4 TSM Equip. Cost 180.17182.64 1,753.08751.75 5 RECC 6.78% 6.78%

6 Annualized Connection Equipment Cost — Finance, Tax, Ins. & Depr.

$12.2238 $118.8778

7 Test Year Secondary Dist. ($/kW-Yr) –

8 Test Year Ongoing Costs Per Residential Unit

9 Meter Services $11.30 $25.7718.46 10 Transformer Maintenance – – 11 Service Maintenance – – 12 Meter Reading 4.85 8.429.13 13 Billing & Collections 15.43 18.7713.46 14 Credit & Collections and Account Setup 3.16 7.193.44

15 Total Ongoing Costs Per Residential Unit $34.76 $60.1444.48

16 Total Connection Cost $46.9747.14 $179.01163.26 17 Average Number of Residential Units

37

18 Master Meter Connection Cost Per Residential Unit

$4.8441 19 Net Marginal Connection Cost Per Residential Unit $42.1373

20 Uncollectibles Factor 0.3253%

21 Uncollectibles $0.14

22 Net Base Discount Per Residential Unit — Annual $42.2787

23 Base Master Meter Discount Per Residential Unit — Monthly

$3.5257

24 Diversity Benefit Adjustment (Illustrative) 2.40

25 Line Loss Adjustment –

26 Net Discount (Monthly) (Illustrative) $1.1217

27 Net Discount (Daily) (Illustrative) $0.0368403847

________________ (a) Master Meter costs uses ML&P-S proxy meter for connection; SL&P proxy meter for ongoing

costs except transformer and service maintenance; transformer and service maintenance calculated for ML&P proxy connection

L. Bill Comparisons 1

Exhibit (PG&E-4), Appendix D, presents illustrative bill comparisons for 2

PG&E’s residential tiered rates. As described in Exhibit (PG&E-3), Chapter 1, 3

the starting point rates are PG&E’s Schedule E-1 and EL-1 rates effective July 1, 4

2019, after being adjusted to have a 4-month summer/8-month winter seasonal 5

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definition. The proposed Schedule E-1 rates are shown in Exhibit (PG&E-4), 1

Appendix C, with CARE customer bills first calculated at E-1 rates, but then 2

reduced via a 35.0 percent line-item discount. Since present rates for 3

Schedule EL-1 were based on a 35.5 percent CARE discount, the bill 4

comparison results shown for this schedule are slightly worse than what can be 5

expected solely as a result of the initiatives proposed in this Phase II. 6

(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 3

ATTACHMENT A

FEASIBILITY OF REMOTE DISPATCH OF RESIDENTIAL

ENERGY STORAGE

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3-AtchA-1

PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 3 2

ATTACHMENT A 3

FEASIBILITY OF REMOTE DISPATCH OF RESIDENTIAL ENERGY 4

STORAGE 5

In the Final Decision on Pacific Gas and Electric Company’s (PG&E or the 6

Utility) 2017 General Rate Case (GRC) Phase II, the California Public Utilities 7

Commission (CPUC or Commission) adopted the Settlement Agreement on 8

Residential Rate Design,1 which requires PG&E to analyze the feasibility of 9

providing a program(s) for residential customers with battery storage that requires 10

remote dispatch of the storage by PG&E or California Independent System Operator 11

(CAISO).2 PG&E has explored the feasibility of enabling remote dispatch of 12

customer-sited energy storage in a number of forums, including (1) the 13

Self-Generation Incentive Program (SGIP) GHG Signal Working Group,3 and 14

(2) two Electric Program Investment Charge (EPIC) projects: EPIC 2.19C (Customer 15

Sited and Behind-the Meter Storage)4 and EPIC 2.02 (Distributed Energy Resource 16

1 Decision (D.) 18-08-013, Ordering Paragraph 13 2 Prior to the next Phase II GRC, PG&E will analyze the feasibility of providing a program

or programs for residential customers with battery storage that requires a minimum amount of remote dispatch of the storage unit at the direction of PG&E or the Independent System Operator. PG&E may conduct this analysis either for inclusion in the next Phase II or as part of another Commission proceeding. The analysis shall consider technical, economic, and ratemaking challenges along with identifying potential benefits to the grid, non-participating customers, and California’s greenhouse gas (GHG) goals. PG&E shall consult with interested stakeholders in conjunction with its analysis. (Settlement Agreement on Residential Rate Design, p. 13, attached to D.18-08-013.)

3 SGIP GHG Signal Working Group (GHG Signal WG) was established by Assigned Commissioner’s Ruling (ACR) on December 29, 2017, and met regularly between January and May 2018. A Final Report from the GHG Signal WG was issued on June 15, 2018 with a Corrected version (the WG Corrected Final Report) issued on September 6, 2018. See https://www.cpuc.ca.gov/uploadedFiles/CPUC_Public_Website/Content/Utilities_and_Industries/Energy/Energy_Programs/Demand_Side_Management/Customer_Gen_and_Storage/GHG%20Working%20Group%20Report%20-%2009.06.18%20-%20corrected.pdf, accessed October 1, 2019.

4 Final Report available at https://www.pge.com/pge_global/common/pdfs/about-pge/environment/what-we-are-doing/electric-program-investment-charge/PGE-EPIC-Project-2.19.pdf, (EPIC Project 2.19 Final Report), accessed October 1, 2019.

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3-AtchA-2

Management System (DERMS)).5 This section describes PG&E’s analyses and the 1

status of the GHG Signal WG and EPIC projects referenced above. 2

In summary, PG&E believes that the time is not yet ripe for programs that 3

require remote dispatch of Residential battery storage. PG&E and the Energy 4

Storage (ES) industry have made significant progress in developing software and 5

hardware and in forecasting and control algorithms required to implement utility or 6

CAISO dispatch at scale. Yet there are still significant challenges in terms of 7

forecasting and control software, consistent and accurate visibility into the state of 8

the ES systems, and indeed customer interest. PG&E and other industry players 9

plan to continue researching through EPIC 3,6 and moving towards scalable 10

solutions via the 2020 and 2023 GRC filing. In the meantime, price and GHG 11

signaling efforts such as those developed through the SGIP proceeding (as well as 12

already-developed Demand Response programs) can provide an alternate way for 13

Residential customers to reduce grid costs and GHG emissions. 14

EPIC Project 2.19C 15

The first EPIC project (Project 2.19C, Customer Sited and Behind-the-Meter 16

Storage) tested the use of customer-sited energy storage technologies to (1) reduce 17

peak loading, especially of local circuits; and (2) absorb Distributed Energy 18

Resources (DER) generation during peak solar production times to address the 19

CAISO’s “duck curve.” Project 2.19C “sought to understand customer interest in and 20

adoption of BTM storage technologies, as well as the technical feasibility for 21

leveraging these assets as a resource for grid services.”7 Project 2.19C 22

demonstrated both the technical potential of Behind-the-Meter (BTM) storage to 23

provide grid reliability support and the challenges in customer acquisition and 24

deployment and dispatching algorithms. PG&E partnered with one Residential and 25

one Commercial energy storage vendor to deploy customer-sited BTM ES 26

5 Final Report available at https://www.pge.com/pge_global/common/pdfs/about-

pge/environment/what-we-are-doing/electric-program-investment-charge/PGE-EPIC-2.02.pdf, (EPIC Project 2.02 Final Report). Accessed October 1, 2019.

6 EPIC 3.03 (DERMS – DER Headend Project), in particular, seeks to address the visibility and forecasting issues (also known as situational awareness), which will be required to monitor and control DERs deployed as part of Wildfire Mitigation Plan grid resilience initiatives.

7 EPIC 2.19C Final Report, p. 1.

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resources, which were controlled and monitored individually and in aggregate by the 1

project team. 2

Project 2.19C found that the Utility “will need to have additional hardware and 3

software systems… to provide accurate visibility into asset performance and 4

availability, and assurances that the BTM energy storage assets will consistently and 5

reliably respond to dispatch signals.”8 In addition, the development of appropriate 6

communication infrastructure, a full-featured DERMS, and improved data accuracy 7

and communications uptime “would enable utilities to leverage BTM energy storage 8

in system planning and operations and realize their full value and capabilities to 9

benefit customers and reduce Greenhouse Gas (GHG) emissions.”9 10

In terms of readiness for rollout beyond the demonstration stage, the team found 11

a number of issues that would need to be resolved before BTM ES could be relied 12

on to provide grid benefits in a wider scale production environment. Such expansion 13

to a production environment would require additional software and hardware 14

investments, a new integrated grid platform, and efficient targeting of potential 15

customers, since even the promise of a free Residential battery was not enough to 16

draw significant interest. Project 2.19C also demonstrated that the ability of BTM ES 17

to serve both customer and grid needs is a two-edged sword: increasing the 18

potential value streams, but requiring sophisticated (and not yet mature) control 19

algorithms, while being limited by customers’ desire to manage bills and provide 20

backup power, which can get in the way of meeting systemwide or local grid needs 21

and reducing GHGs.10 22

In summary, EPIC Project 2.19C found that while BTM ES could technically be 23

managed to respond to utility signals to help meet grid needs, existing systems are 24

far from scalable and “plug and play,” and significant customer interest in utility 25

signaling has not yet developed. 26

EPIC Project 2.02 27

The second EPIC Project (EPIC 2.02, Distributed Energy Resource 28

Management System (DERMS), or the “DERMS Demo”),11 focused on defining and 29

8 Ibid. 9 Ibid., p. 2. 10 Ibid., pp. 5-7. 11 EPIC Projects 2.19C and 2.02 shared the same DERMS and were conducted over the

same timeframe on the same distribution feeder, in San Jose, California.

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deploying proof of concept DERMS software, in “an industry leading field 1

demonstration of optimized control of a portfolio of 3rd party aggregated behind-the-2

meter (BTM) solar and energy storage and utility front-of-the-meter (FTM) energy 3

storage. These assets provided distribution capacity and voltage support services 4

while also allowing for participation of these same DERs in the CAISO wholesale 5

market … to test DER value stacking, often referred to as multiple use applications 6

(MUA).”12 As part of the Project, PG&E developed a scaled-down Advanced 7

Distribution Management Systems (ADMS) to provide visibility and local distribution 8

system power modeling. Figure 3A-113 provides a simplified overview of the 9

DERMS Demo. 10

FIGURE 3A-1 SIMPLIFIED DERMS DEMO OVERVIEW

The main objective of the DERMS Demo was to “test and demonstrate that new 11

technologies can provide the functionality to monitor and control DERs to manage 12

system constraints and evaluate the potential value of DER flexibility to the grid. 13

The DERMS Demo demonstrated that value from DERs to provide grid services 14

could be realized.”14 That value included simulated participation in the CAISO 15

market, including as a Proxy Demand Resource (PDR) to decrease load, and 16

PG&E’s Excess Supply DR Pilot15 to increase load. However, the Project 17

12 EPIC 2.02 Final Report, p. 2. 13 Ibid., p. 3. 14 Ibid., p. 5. 15 See https://olivineinc.com/services/our-work/xsp/.

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concluded that “[t]o preserve distribution safety and reliability, distribution dispatch 1

must have priority over wholesale market operations and visibility across 2

both systems.”16 3

The DERMS Demo project team concluded that the Project “successfully 4

demonstrated the potential of DERMS technology, while creating key learnings that 5

helped further the industry and identify ADMS and DERMS needs for PG&E . . . 6

Through collaboration with the participating vendors, other PG&E demonstrations, 7

and industry leaders, the DERMS Demo progressed the state of the industry.”17 8

However, “[o]utstanding policy, regulatory, and program ambiguity make it imprudent 9

to implement a full-scale DERMS immediately.”18 PG&E is proposing further 10

DERMS work in EPIC 3, and is pursuing more general technology investments 11

through the Integrated Grid Platform Program as proposed in PG&E’s 2020 GRC.19 12

GHG Signal WG 13

Finally, the GHG Signal WG20 was tasked with developing “a ‘GHG signal’ 14

provided to participants in advance [which] could help SGIP energy storage systems 15

to operate (i.e., charge and discharge) to reduce net GHG emissions to at least 16

zero.”21 Over a period of six months in 2018, the Working Group developed 17

recommendations for the content and delivery mechanisms of a GHG signal 18

(i.e., real-time estimates of marginal GHG impacts of load, as well as forecasts of 19

same at various timescales). The Working Group also modeled the ability of the 20

signal to reduce GHG emissions for both residential and non-residential customers 21

under a wide variety of rates. These recommendations and modeling results were 22

summarized in the WG Corrected Final Report, which was published along with a 23

16 EPIC 2.02 Final Report, p. 8. 17 Ibid., p. 10. 18 Ibid., p. 11. 19 For an overall discussion of grid modernization efforts in California, including PG&E’s

Integrated Grid Platform, see https://www.utilitydive.com/news/pge-may-answer-the-billion-dollar-grid-modernization-question/561146/.

20 The GWG Signal WG was “facilitated by Alternative Energy Systems Consulting (AESC) and consisted of the SGIP program administrators (PAs) – Pacific Gas & Electric Company (PG&E), Southern California Edison Company (SCE), Southern California Gas Company (SoCalGas) and the Center for Sustainable Energy (CSE) – California Public Advocate’s Office, solar and energy storage companies and trade associations, energy non-profits, and ED staff.” See D.19-08-001, p. 6.

21 ACR filed December 29, 2017, p. 3.

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3-AtchA-6

CPUC Staff Proposal on September 6, 2018, followed by a Revised Staff Proposal 1

on December 31, 2018, and a Final Decision (D.19-08-001, the GHG SGIP 2

Decision) effective August 1, 2019. 3

Based on the extensive collaboration among interested stakeholders, including 4

multiple rounds of comments, the GHG SGIP Decision specified a five-minute 5

real-time GHG signal along with a 15-minute forecast, an hour-ahead forecast, and a 6

day-ahead forecast. In addition, the SGIP PAs were directed to work with the GHG 7

signal vendor and industry stakeholders to identify the type of longer-term forecasts 8

that would be most useful (e.g., the probabilities of GHG emissions being in various 9

ranges depending on time of day and year, and other factors). While the GHG SGIP 10

Decision established incentive reductions based on poor GHG performance only for 11

non-residential customers, the development of a robust GHG emissions forecasting 12

infrastructure will enable residential customers with energy storage (many of whom 13

have the desire to reduce their GHG emissions) to do so once both the GHG signal 14

and control software from vendors are available.22 15

PG&E is continuing its efforts to enable signaling and potential remote dispatch 16

of residential ES, either individually or via aggregators, along with ES industry 17

partners and other stakeholders. These efforts are primarily through the EPIC 3 18

program, PG&E’s proposed Integrated Grid Platform, and the GHG signal under 19

development under SGIP (with rollout in 2020). PG&E anticipates that production-20

scale remote dispatch by the utility and/or CAISO will likely be possible in the 21

mid-2020s, but is not yet a reality. 22

22 The GHG SGIP Decision requires the PAs to contract with a qualified GHG signal

vendor and to provide an interim GHG signal within 150 days of adoption (i.e., no later than December 30, 2019), and a final signal within 240 days of adoption (i.e., no later than March 29, 2020). The PAs selected the GHG signal vendor (WattTime) on November 1, 2019; development of the interim GHG signal is now underway.

Pacific Gas and Electric Company2020 General Rate Case - Phase II

Exhibit (PG&E-3), Chapter 3, Attachment B, Errata to May 2020 UpdatePresent and Illustrative Residential Rate Designs

E-1, EM, ES, ESR, ETDistr Gen PPP CIA Other Total Distr Gen PPP CIA Other Total

ENERGY CHARGE (/kWh) Baseline Usage .09671 .11752 .01296 (.03542) .05196 .24373 .09143 .12066 .01338 (.04083) .05196 .23659 101% - 400% of Baseline .09671 .11752 .01296 .02757 .05196 .30672 .09143 .12066 .01338 .02031 .05196 .29773 Over 400% of Baseline .09671 .11752 .01296 .25823 .05196 .53738 .09143 .12066 .01338 .24420 .05196 .52162

MINIMUM CHARGE(/meter/day) * .02123 .00166 .32854 $10.00 * .02192 .00000 .00166 .32854 $10.00(/kWh) .05160 .05160

ES DISCOUNT (/dwelling unit/day) .03115 .03115 0.95 .03847 .03847 1.17

ES MARL (/kWh) .03640 .01251 .04892 .03641 .01251 .04892

ET DISCOUNT (/dwelling unit/day) .06181 .06181 1.88 .06813 .06813 2.07

ET MARL (/kWh) .03640 .01251 .04892 .03641 .01251 .04892

* Calculated residually as total less sum of other charges. * Calculated residually as total less sum of other charges.

E-TOU-C (Tiered)Distr Gen PPP CIA Other Total Distr Gen PPP CIA Other Total

SUMMER ENERGY CHARGE ($/kWh) Peak .12767 .16735 .01296 .05339 .05196 .41333 .13416 .19992 .01338 .04648 .05196 .44589 Off-Peak .11767 .11391 .01296 .05339 .05196 .34989 .11416 .13648 .01338 .04648 .05196 .36245 Baseline Credit (.08633) (.08633) (.08652) (.08652)WINTER ENERGY CHARGE ($/kWh) Peak .07935 .11859 .01296 .05338 .05196 .31624 .08456 .11589 .01338 .04648 .05196 .31225 Off-Peak .07705 .10356 .01296 .05338 .05196 .29891 .08124 .09086 .01338 .04648 .05196 .28390 Baseline Credit (.08633) (.08633) (.08652) (.08652)MINIMUM CHARGE(/meter/day) * .02123 .00000 .00166 .32854 $10.00 * .02192 .00000 .00166 .32854 $10.00(/kWh) .05160 .05160

* Calculated residually as total less sum of other charges. * Calculated residually as total less sum of other charges.

E-TOU B (Non-Tiered)Distr Gen PPP CIA Other Total Distr Gen PPP CIA Other Total

SUMMER ENERGY CHARGE ($/kWh)Peak .11515 .22242 .01296 .00000 .05196 .40249 .12159 .25200 .01338 .00000 .05196 .43893 Off-Peak .11515 .11936 .01296 .00000 .05196 .29943 .12159 .12894 .01338 .00000 .05196 .31587 WINTER ENERGY CHARGE ($/kWh)Peak .08452 .11558 .01296 .00000 .05196 .26502 .08149 .12839 .01338 .00000 .05196 .27521 Off-Peak .08452 .09678 .01296 .00000 .05196 .24622 .08149 .08959 .01338 .00000 .05196 .23641

MINIMUM CHARGE(/meter/day) * .02123 .00166 .32854 $10.00 * .02192 .00000 .00166 .32854 $10.00(/kWh) .05160 .05160

* Calculated residually as total less sum of other charges. * Calculated residually as total less sum of other charges.

PRESENT RATES (May 1, 2020) PROPOSED RATES

(PG&E-3)

3-AtchB-1

Pacific Gas and Electric Company2020 General Rate Case - Phase II

Exhibit (PG&E-3), Chapter 3, Attachment B, Errata to May 2020 UpdatePresent and Illustrative Residential Rate Designs

PRESENT RATES (May 1, 2020) PROPOSED RATES

E-TOU-D (Non-Tiered)Distr Gen PPP CIA Other Total Distr Gen PPP CIA Other Total

SUMMER ENERGY CHARGE (/kWh) Peak .12037 .17947 .01296 .00000 .05196 .36476 .14713 .24740 .01338 .00000 .05196 .45986 Off-Peak .11037 .09451 .01296 .00000 .05196 .26980 .11713 .14244 .01338 .00000 .05196 .32490

WINTER ENERGY CHARGE (/kWh) Peak .08780 .13817 .01296 .00000 .05196 .29089 .08454 .12816 .01338 .00000 .05196 .27805 Off-Peak .08550 .12309 .01296 .00000 .05196 .27351 .08101 .09308 .01338 .00000 .05196 .23944

MINIMUM CHARGE(/meter/day) * .02123 .00000 .00166 .32854 $10.00 * .02192 .00000 .00166 .32854 $10.00(/kWh) .05160 .05160

* Calculated residually as total less sum of other charges. * Calculated residually as total less sum of other charges.

E-6 (Tiered)Distr Gen PPP CIA Other Total Distr Gen PPP CIA Other Total

SUMMER ENERGY CHARGE (/kWh) Peak Baseline Usage .30700 .26468 .01296 (.23171) .05196 .40489 .28458 .26234 .01338 (.04004) .05196 .57222 Over Baseline .30700 .26468 .01296 (.14538) .05196 .49122 .28458 .26234 .01338 .04648 .05196 .65874 Part-Peak Baseline Usage .12442 .14175 .01296 (.04464) .05196 .28645 .11108 .17941 .01338 (.04004) .05196 .31579 Over Baseline .12442 .14175 .01296 .04169 .05196 .37278 .11108 .17941 .01338 .04648 .05196 .40231 Off-Peak Baseline Usage .06356 .09157 .01296 (.00883) .05196 .21122 .06113 .10923 .01338 (.04004) .05196 .19566 Over Baseline .06356 .09157 .01296 .07750 .05196 .29755 .06113 .10923 .01338 .04648 .05196 .28218

WINTER ENERGY CHARGE (/kWh) Part-Peak Baseline Usage .11964 .11942 .01296 (.07159) .05196 .23239 .09793 .12705 .01338 (.04004) .05196 .25028 Over Baseline .11964 .11942 .01296 .01474 .05196 .31872 .09793 .12705 .01338 .04648 .05196 .33680 Off-Peak Baseline Usage .08066 .10563 .01296 (.03565) .05196 .21556 .07895 .09325 .01338 (.04004) .05196 .19750 Over Baseline .08066 .10563 .01296 .05068 .05196 .30189 .07895 .09325 .01338 .04648 .05196 .28402

MINIMUM CHARGE(/meter/day) * .02123 .00166 .32854 $10.00 * .02192 .00000 .00166 .32854 $10.00(/kWh) .05160 .05160

* Calculated residually as total less sum of other charges. * Calculated residually as total less sum of other charges.

(PG&E-3)

3-AtchB-2

Pacific Gas and Electric Company2020 General Rate Case - Phase II

Exhibit (PG&E-3), Chapter 3, Attachment B, Errata to May 2020 UpdatePresent and Illustrative Residential Rate Designs

PRESENT RATES (May 1, 2020) PROPOSED RATES

EVA (Electric Vehicles)Distr Gen PPP CIA Other Total Distr Gen PPP CIA Other Total

SUMMER ENERGY CHARGE (/kWh) Peak .20130 .27692 .01296 .00000 .05196 .54314 .20346 .25522 .01338 .00000 .05196 .52402 Part-Peak .10066 .13345 .01296 .00000 .05196 .29903 .10282 .11175 .01338 .00000 .05196 .27991 Off-Peak .01449 .06707 .01296 .00000 .05196 .14648 .03665 .06537 .01338 .00000 .05196 .16736

WINTER ENERGY CHARGE ($/kWh) Peak .21432 .10348 .01296 .00000 .05196 .38272 .18560 .11251 .01338 .00000 .05196 .36345 Part-Peak .10716 .06465 .01296 .00000 .05196 .23673 .07844 .08766 .01338 .00000 .05196 .23144 Off-Peak .01543 .06946 .01296 .00000 .05196 .14981 .00671 .08766 .01338 .00000 .05196 .15971 MINIMUM CHARGE(/meter/day) * .02123 .00166 .32854 $10.00 * .02192 .00000 .00166 .32854 $10.00(/kWh) .05160 .05160

* Calculated residually as total less sum of other charges. * Calculated residually as total less sum of other charges.

EVB (Electric Vehicles)Distr Gen PPP CIA Other Total Distr Gen PPP CIA Other Total

SUMMER ENERGY CHARGE (/kWh) Peak .19527 .27692 .01296 .00000 .05196 .53711 .20048 .25522 .01338 .00000 .05196 .52104 Part-Peak .09764 .13345 .01296 .00000 .05196 .29601 .09984 .11175 .01338 .00000 .05196 .27693 Off-Peak .01406 .06707 .01296 .00000 .05196 .14605 .03367 .06537 .01338 .00000 .05196 .16438

WINTER ENERGY CHARGE ($/kWh) Peak .20790 .10348 .01296 .00000 .05196 .37630 .18262 .11251 .01338 .00000 .05196 .36048 Part-Peak .10395 .06465 .01296 .00000 .05196 .23352 .07546 .08766 .01338 .00000 .05196 .22847 Off-Peak .01497 .06946 .01296 .00000 .05196 .14935 .00373 .08766 .01338 .00000 .05196 .15674

CUSTOMER CHARGE (/meter/day) .04928 .04928 $1.50 .04928 .04928 $1.50

MINIMUM CHARGE(/meter/day) * .02123 .00166 .32854 $10.00 * .02192 .00000 .00166 .32854 $10.00(/kWh) .05160 .05160

* Calculated residually as total less sum of other charges. * Calculated residually as total less sum of other charges.

(PG&E-3)

3-AtchB-3

Pacific Gas and Electric Company2020 General Rate Case - Phase II

Exhibit (PG&E-3), Chapter 3, Attachment B, Errata to May 2020 UpdatePresent and Illustrative Residential Rate Designs

PRESENT RATES (May 1, 2020) PROPOSED RATES

EV2A (Electric Vehicles)Distr Gen PPP CIA Other Total Distr Gen PPP CIA Other Total

SUMMER ENERGY CHARGE (/kWh) Peak .23029 .18340 .01296 .00000 .05196 .47861 .23910 .20626 .01338 .00000 .05196 .51070 Part-Peak .16451 .13869 .01296 .00000 .05196 .36812 .17332 .16155 .01338 .00000 .05196 .40021 Off-Peak .00364 .09755 .01296 .00000 .05196 .16611 .01245 .12041 .01338 .00000 .05196 .19820

WINTER ENERGY CHARGE (/kWh) Part-Peak .16005 .12653 .01296 .00000 .05196 .35150 .15847 .11843 .01338 .00000 .05196 .34224 Part-Peak .15584 .11404 .01296 .00000 .05196 .33480 .15426 .10594 .01338 .00000 .05196 .32554 Off-Peak .01063 .09056 .01296 .00000 .05196 .16611 .00905 .08246 .01338 .00000 .05196 .15685MINIMUM CHARGE(/meter/day) * .02123 .00166 .32854 $10.00 * .02192 .00000 .00166 .32854 $10.00(/kWh) .05160 .05160

* Calculated residually as total less sum of other charges. * Calculated residually as total less sum of other charges.

(PG&E-3)

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(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 4

COMMERCIAL AND INDUSTRIAL RATE DESIGN

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PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 4

COMMERCIAL AND INDUSTRIAL RATE DESIGN

TABLE OF CONTENTS

A. Introduction ............................................................................................................ 4-1

B. Summary of Proposals.......................................................................................... 4-3

C. Small Light and Power Rate Design .................................................................... 4-4

1. Overview ......................................................................................................... 4-4

2. Rate Design .................................................................................................... 4-4

3. Changes to Distribution and Generation Rates ............................................ 4-6

4. Meet and Confer With Small Business Utility Advocates and the Public Advocates Office at the California Public Utilities Commission ........ 4-6

5. Schedule E-CARE and the Food Bank Discount.......................................... 4-8

D. Rate Design for Schedules A-10 and B-10 .......................................................... 4-8

1. Overview ......................................................................................................... 4-8

2. Rate Design .................................................................................................... 4-9

3. Changes to Distribution and Generation Rates .......................................... 4-10

E. Rate Design for Schedules E-19, E-20, B-19, and B-20................................... 4-10

1. Overview ....................................................................................................... 4-10

2. Rate Design .................................................................................................. 4-11

3. Changes to Distribution and Generation Rates .......................................... 4-11

F. Rate Design for Standby (Schedules S and SB) ............................................... 4-12

1. Overview ....................................................................................................... 4-12

2. Rate Design .................................................................................................. 4-13

3. Changes to Distribution and Generation Rates .......................................... 4-14

G. Rate Design Illustrations Requested in D.18-08-013 ........................................ 4-14

H. Conclusion ........................................................................................................... 4-15

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PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 4 2

COMMERCIAL AND INDUSTRIAL RATE DESIGN 3

A. Introduction 4

In this chapter Pacific Gas and Electric Company (PG&E) proposes rates for 5

the Commercial and Industrial (C&I) customers. In this proceeding, PG&E is 6

proposing changes to generation, distribution and Public Purpose Program 7

(PPP) revenue allocation and rate design. PG&E is not making any proposals 8

for revenue allocation and rate design for other components of rates.1 9

Generation, distribution and PPP revenue allocation, as well as PPP rate 10

design,2 is described in Chapter 2. In this chapter, PG&E summarizes its 11

proposals for generation and distribution rate design. 12

Under the transition plan adopted by Decision (D.) 18-08-013, rates with 13

new Time-of-Use (TOU) periods became available on an opt-in basis for C&I 14

customers beginning in November 2019. From the date when the rates with 15

new TOU periods became available on an opt-in basis, until March 2021, PG&E 16

will retain all C&I rates on both the old TOU structure (referred to herein as 17

“legacy rates”) as well as the new TOU structure (rates with new TOU periods, 18

or “B Series” rates). In March 2021, PG&E will begin the mandatory transition of 19

customers to the rates with new TOU periods for those customers who have not 20

opted-in. In the table below, PG&E provides a summary of the rate schedules 21

that are addressed in this chapter. 22

1 Rate design includes rate components for transmission, distribution, generation, PPP,

Nuclear Decommissioning, Department of Water Resources (DWR) Bond Charge, New System Generation Charges, the Energy Cost Recovery Amount, Competition Transition Charges, and the Power Charge Indifference Adjustment (PCIA).

2 PPP rates are designed in accordance with the guidelines described in Chapter 1 using the revenue allocation provided in Chapter 2.

(PG&E-3)

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TABLE 4-1 PG&E’S COMMERCIAL AND INDUSTRIAL RATE SCHEDULES

Line No. Section

Legacy Rate Schedule (Short Name)

Rate With New TOU Periods (Short Name)

1 C A-1/A-1TOU B-1 2 C A-6 B-6 3 C A-15 B-15 4 C TC-1 N/C 5 C N/A B-1Store 6 D A-10/A-10TOU B-10 7 E E-19/E-19V B-19/B-19V 8 E E-19/E-19V Option R B-19/B-19V Option R 9 E N/A B-19/B-19V Option S

10 E E-20 B-20 11 E E-20 Option R B-20 Option R 12 E N/A B-20 Option S 13 F S SB

Also beginning March 2021, rates with grandfathered TOU periods will 1

become available for solar customers that have met the grandfathering 2

requirements under D.17-01-006 and successor decisions.3 D.18-08-013 3

adopted the Settlement Agreement on TOU Rates for Grandfathered Solar 4

Customers, which established transition plans through 2023 for Schedules A-6, 5

E-19V Option R, E-19 Option R and E-20 Option R. PG&E is not seeking a 6

change to those transition plans in this proceeding.4 In addition, the Settlement 7

adopted adjustments for solar grandfathered rates for Schedules A-1TOU, 8

A-10TOU and the non-Option R versions of Schedules E-19V, E-19 and E-20 9

that would occur in one step (that is, no transition plan was required) beginning 10

when these rates would be used exclusively by grandfathered solar customers. 11

This is expected to begin in March 2021. While adjustments to the solar 12

grandfathered rates for Schedules A-1TOU, A-10TOU and the non-Option R 13

versions of Schedules E-19V, E-19 and E-20 could be considered in this 14

proceeding, PG&E has concluded that no changes are necessary and that the 15

provisions of the Settlement Agreement on TOU Rates for Grandfathered Solar 16

Customers should continue until the 2023 General Rate Case (GRC) Phase II. 17

3 D.17-01-006 was later modified by D.17-02-017 and D.17-10-018. 4 In addition, pursuant to D.18-08-013, the transition plan for rate changes for eligible

grandfathered solar customers served under Schedule RES-BCT was filed as Advice Letter 5379-E-A and subsequently approved by the California Public Utilities Commission (Commission). PG&E is not proposing a modification to the transition plan for Schedule RES-BCT in this proceeding.

(PG&E-3)

4-3

Accordingly, PG&E is not proposing any changes in this proceeding to the rates 1

and methodologies set forth in the Settlement Agreement on TOU Rates for 2

Grandfathered Solar Customers approved by D.18-03-013. 3

The remainder of this chapter is organized as follows: 4

Section B – Summary of Proposals 5

Section C – Small Light and Power Rate Design 6

Section D – Rate Design for Schedules A-10 and B-10 7

Section E – Rate Design for Schedules E-19, E-20, B-19 and B-20 8

Section F – Rate Design for Standby (Schedules S and SB) 9

Section G – Rate Design Illustrations Requested in D.18-08-013 10

Section H – Conclusion 11

Appendix A of Exhibit (PG&E-4) provides recorded data for the customer 12

classes presented in this chapter. Appendix C, “Present and Proposed Rates,” 13

of Exhibit (PG&E-4), and Attachment B to this chapter, contain PG&E’s present 14

and proposed total and unbundled rates for each customer class. Appendix D, 15

“Illustrative Bill Impacts,” of Exhibit (PG&E-4), presents the bill comparison 16

impacts of PG&E’s proposed rates. Finally, Appendix G of Exhibit (PG&E-4) 17

presents illustrative rates designs for C&I rate schedules as required by 18

D.18-08-013. 19

B. Summary of Proposals 20

As discussed in Chapter 1 of this exhibit, a key objective in PG&E’s C&I rate 21

design proposal is to retain the rate designs adopted by PG&E’s 2017 GRC 22

Phase II proceeding (D.18-08-013) as customers are being transitioned to rates 23

with new TOU periods. The following proposals are discussed in greater detail 24

in the remaining sections of this chapter: 25

For the revenue allocation changes in this proceeding, as well as revenue 26

requirement changes for rate changes between GRCs, continue to apply the 27

rules for rate changes between GRCs adopted by D.18-08-013, except as 28

noted below; 29

Revise Schedule B-6 to provide a greater TOU differentiation in 2022, no 30

later than November 1; 31

Eliminate the voluntary TOU meter charges on legacy rate Schedules A-6 32

and E-19 voluntary; 33

(PG&E-3)

4-4

Revise generation charges for Schedule SB to better reflect cost, and adjust 1

the basis for changing rates for revenue allocation and revenue requirement 2

changes in the future; and 3

Adjust generation energy rates in the winter, where necessary, so that the 4

Super Off Peak (SOP) rate is not less than the PCIA. 5

C. Small Light and Power Rate Design 6

As noted above, Small Light and Power (SLP) includes Schedules A-1, 7

A-1TOU, A-6, A-15, B-1, B-6, B-15, B-1Store and TC-1. PG&E’s eligibility 8

boundary between SLP and Schedules A-10 and B-10 is 75 kilowatts (kW). 9

Customers that have demands in excess of 75 kW may not take service on the 10

SLP rate schedules. In general, these rate schedules consist of a customer 11

charge and volumetric energy charges. 12

1. Overview 13

PG&E proposes the following rate design for the SLP: 14

Retain the current 75 kW eligibility threshold; 15

Retain the seasons and TOU periods adopted by D.18-08-013; 16

For all rate schedules, except as specifically proposed for Schedule B-6, 17

continue the existing rate structures and rules for changes between 18

GRCs in order to implement the revenue allocation results determined in 19

this proceeding and for revenue requirement changes before the next 20

GRC Phase II proceeding to ensure rate stability during the transition to 21

rates with new TOU periods; 22

Increase the Schedule B-6 TOU price differentials in 2022, no later than 23

November 1; and 24

Eliminate the voluntary TOU meter charges on legacy Schedule A-6. 25

2. Rate Design 26

As discussed above, in this proceeding PG&E proposes to continue the 27

seasons, TOU periods and rate design established by D.18-08-013 for all 28

SLP rate schedules except noted below for Schedule B-6. 29

PG&E proposes to continue the customer charges on Schedules 30

A1-TOU, A-6, B-1, B-1 Store and B-6: $10 for single-phase and $25 for 31

poly-phase service. In addition, PG&E proposes to eliminate the current 32

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4-5

TOU meter charge applicable on Schedule A-6.5 Currently, Schedule B-1 1

has TOU differentials in only the generation component of the rate. The 2

prescribed differential in the summer is approximately seven cents per 3

kilowatt-hour (¢/kWh) (on-peak versus off-peak). This design compares to a 4

fully time-differentiated, fully-scaled Equal Percent of Marginal Cost (EPMC) 5

rate differential of about 3433 ¢/kWh. PG&E recommends retaining these 6

moderate TOU differentials for this GRC cycle during the transition of 7

customers to the new TOU periods and consider increasing the TOU 8

differential on this rate schedule in the 2023 GRC Phase II proceeding. 9

The design authorized for Schedule B-6 in D.18-08-013 provides for an 10

on-peak versus off-peak differential in the summer of about 12 ¢/kWh with 11

no summer partial-peak period. This rate features time differentiation in 12

both the generation and distribution rate components. In this proceeding, 13

PG&E proposes to retain the TOU differential adopted by D.18-08-013 14

during the transition of customers to the mandatory TOU rates. Once the 15

transition is complete, PG&E proposes to increase the TOU differentials for 16

Schedule B-6. Specifically, PG&E proposes to set the TOU differential at 17

the mid-point between fully-time-differentiated rates (with a 3230 ¢/kWh 18

differential) and the currently authorized rates, resulting in an on-peak 19

versus off-peak differential in the summer of about 2221 ¢/kWh. By 20

adopting revised rate design for Schedule B-6, a beneficial rate is available 21

to customers that can shift load that has a much wider TOU differential than 22

Schedule B-1. By waiting to make this change until 2022, customers are not 23

impacted by a change to pricing during the mandatory transition to the new 24

TOU period hours and rates. 25

PG&E proposes to continue the current structure for both 26

Schedules TC-1 and B-15. Energy rates for Schedule B-15 will be equal to 27

the seasonally differentiated, non-TOU equivalent of Schedule B-1. 28

5 PG&E proposes to eliminate the voluntary TOU meter charges on the legacy

Schedules A-6 and E-19 V. Voluntary TOU meter charges were first approved to recover the incremental cost of the TOU meter and TOU program administrative cost. As interval meters have been installed, these meter charges have only been applied to customers still served with legacy TOU meters. These charges no longer serve their original purpose because TOU meters and TOU service are now standard. For that reason, voluntary TOU meter charges were not included in the B Series schedules.

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Schedule B-15 will be subject to the single-phase customer charge for 1

Schedule B-1 and will continue to include a $25 facility charge. 2

Schedule TC-1 will continue in its current form as a non-time differentiated 3

rate. Schedule TC-1 will continue to include a $15 customer charge. 4

Schedules A-1, A-6 and A-15 will retain the same customer charge and 5

facility charge as their B Series counterpart rates. As discussed above, 6

PG&E proposes to eliminate the voluntary TOU meter charge on legacy 7

Schedule A-6. Rate design changes will be implemented as provided in 8

Section 3 below until these rates are available only to solar grandfathered 9

customers. 10

In D.18-08-013, the Commission adopted a new SLP schedule, 11

Schedule B1-Store, for eligible customers with storage systems. PG&E 12

expects Schedule B1-Store will available for enrollment in August 2020. 13

PG&E proposes that the design adopted by D.18-08-013 be continued 14

subject to the rules for changing generation and distribution charges 15

described in Section 3. 16

3. Changes to Distribution and Generation Rates 17

Changes to legacy rates and the B Series rates would continue to use 18

the existing rules for changes between GRCs adopted by D.18-08-013 in 19

order to implement the revenue allocation adopted in this proceeding and for 20

revenue requirement changes before the next GRC Phase II proceeding. 21

These rules are summarized for the SLP customer class in Attachment A, 22

Part A. 23

4. Meet and Confer With Small Business Utility Advocates and the Public 24

Advocates Office at the California Public Utilities Commission 25

The Settlement Agreement on SLP Rate Design adopted by 26

D.18-08-013 required that PG&E schedule a ‘meet and confer’ with the 27

Public Advocates Office at the California Public Utilities Commission 28

(Cal Advocates) and Small Business Utility Advocates (SBUA) six months 29

prior to filing its next GRC Phase II application. The purpose of the meet 30

and confer was to discuss whether A-1 DMD or other rate schedules should 31

be proposed in the next GRC Phase II proceeding, for the purpose of 32

providing a meaningful rate option for small businesses to manage energy 33

(PG&E-3)

4-7

costs. The Settlement further provided that PG&E would submit testimony 1

in this GRC Phase II proceeding on the results of that meet and confer. 2

On February 5, 2019, PG&E held a conference call with SBUA and 3

Cal Advocates. After PG&E reviewed the settlement requirement, SBUA 4

indicated that they were generally in favor of options for small commercial 5

customers and had requested the meet and confer to consider the possibility 6

of additional options in the 2020 GRC Phase II. PG&E agreed that the 7

reference to A-1-DMD was intended as an example of one such possible 8

rate option. SBUA said that they had been in favor of A-1-DMD, but that 9

was not the only possibility. The parties discussed the benefits and 10

drawbacks of a rate with a low TOU differential. PG&E described the 11

options that came out of the 2017 GRC II proceeding, including default 12

A-1TOU (currently Schedule B-1) with a low 7 cent differential and A-6 13

(currently Schedule B-6) with a higher differential. PG&E indicated that 14

while generally in favor of a demand charges, PG&E was not currently 15

planning additional rate options for the next Phase II. In addition, PG&E 16

indicated that changing designs radically in Phase II would disrupt the 17

transition to the new TOU periods which will likely occur while the 2020 GRC 18

Phase II was pending. 19

In response to an inquiry from Cal Advocates regarding the decision’s 20

reference to a wider TOU differential for A-6 (currently Schedule B-6), PG&E 21

asked if a somewhat higher TOU differential on A-6 (currently Schedule B-6) 22

would be a benefit. Both CAL Advocates and SBUA indicated that they 23

would need to study the question. PG&E stated that illustrative rates would 24

certainly be filed in the proceeding for consideration by the Commission and 25

the Parties. 26

On April 3, 2019, SBUA, Cal Advocates, and PG&E held a follow-up 27

conference call. SBUA indicated that they were in favor of considering a 28

wider TOU differential for A-6 (currently Schedule B-6). Cal Advocates 29

preferred to wait to widen the TOU differential for A-6 (currently 30

Schedule B-6) until it could be reviewed further. SBUA asked about 31

changes to TOU hours. PG&E stated that it was unlikely to attempt to 32

change TOU hours in the 2020 GRC, although future changes to TOU 33

periods would be reviewed as part of the filing. SBUA indicated that they 34

(PG&E-3)

4-8

were concerned with small business customers adjusting to TOU hours and 1

suggested considering alternative rate structures. PG&E said it would prefer 2

not to add a new rate schedule. No consensus with regard to additional rate 3

options or alternative structures was reached during the meet and confer. 4

5. Schedule E-CARE and the Food Bank Discount 5

Schedule E-CARE is the California Alternate Rates for Energy (CARE) 6

program for non-profit group living facilities served on non-Residential rates. 7

The E-CARE discount is implemented as a dollar per kWh discount where 8

the customer’s bill is equal to its otherwise applicable commercial charges, 9

less a discount equal to the product of its total kWh usage and the Schedule 10

E-CARE discount rate per kWh. The Schedule E-CARE discount rate per 11

kWh is designed to provide approximately the same percentage discount 12

relative to Non-CARE rates, on average, as Residential rates. 13

The Schedule E-CARE total rate per kWh discount is unbundled into 14

three parts: (1) the waiver of the CARE surcharge component of PPP rates; 15

(2) a distribution discount; and (3) the exemption to the California DWR 16

Bond Charge. By providing the distribution CARE discount in the 17

distribution function, PG&E allows all customers, whether Customer Choice 18

Aggregator, Direct Access or bundled service, to receive the same CARE 19

discount. PG&E proposes to retain the current E-CARE design and update 20

the rate discounts as the overall residential CARE discount changes. 21

The Commission authorized a 20 percent discount to eligible food banks 22

in D.18-08-013. PG&E proposes to continue the food bank discount in 23

this GRC. 24

D. Rate Design for Schedules A-10 and B-10 25

This section includes rate design for Schedules A-10, A-10 TOU and B-10. 26

Customers with demand less than 500 kW may take service on these rate 27

schedules. These schedules generally consist of a customer charge, a 28

maximum (non-coincident) demand charge and energy charges. 29

1. Overview 30

PG&E proposes the following rate design for Schedules A-10 and B-10: 31

Retain the seasons and TOU periods adopted by D.18-08-013; and 32

(PG&E-3)

4-9

Continue the existing rate structures and rules for changes between 1

GRCs in order to implement the revenue allocation results determined in 2

this proceeding and for revenue requirement changes before the next 3

GRC Phase II proceeding to ensure rate stability during the transition to 4

rates with new TOU periods. 5

2. Rate Design 6

As discussed above, in this proceeding, PG&E proposes to continue the 7

rate design established by D.18-08-013 for Schedules A-10 and B-10. 8

PG&E’s proposal retains the rules for changing the customer charge 9

authorized by D.18-08-013 with changes in revenue allocation in this 10

proceeding and revenue requirement changes. 11

D.18-08-013 adopted a TOU differential for Schedule B-10 only in the 12

generation component of the rate. The prescribed differential in the summer 13

is approximately 9.4 ¢/kWh (on-peak to off-peak at secondary voltage). This 14

design compares to a fully-time-differentiated, fully-scaled EPMC rate 15

differential of about 3432 ¢/kWh (distribution and generation). PG&E 16

recommends retaining this moderate TOU differential for this GRC cycle 17

during the transition of customers to the new TOU periods; increases to the 18

TOU differential on this rate schedule in should instead be considered in 19

PG&E’s 2023 GRC Phase II proceeding. PG&E proposes to retain the 20

current level of non-coincident demand charge, subject to the revenue 21

allocation changes in this proceeding, to recover a portion of distribution 22

costs that do not vary by time of day. Customers whose demand is less 23

than 500 kW also have the choice of electing voluntary service under 24

Schedule B-19. Schedule B-19V offers a much wider TOU differential in 25

both the generation and distribution components of the rate than 26

Schedule B-10 and provides a beneficial option to customers that can shift 27

load. 28

Under this proposal, Schedule A-10 will retain the same customer 29

charge as the B Series counterpart rate. Rate design changes will be 30

implemented as provided in Section 3, below, until these rates are available 31

only to solar grandfathered customers. 32

(PG&E-3)

4-10

3. Changes to Distribution and Generation Rates 1

Changes to legacy rates (A-10) and the new B Series rates (B-10) would 2

use the existing rules for changes between GRCs adopted by D.18-08-013 3

in order to implement the revenue allocation adopted in this proceeding and 4

for revenue requirement changes before the next GRC Phase II proceeding. 5

These rules are summarized for Schedules A-10 and B-10 in Attachment A, 6

Part B. 7

E. Rate Design for Schedules E-19, E-20, B-19, and B-20 8

This section includes rate design for Schedules E-19, E-19V, E-20, B-19, 9

B-19V, and B-20. Customers with demands less than 500 kW may elect to take 10

service on Schedules E-19V and B-19V. Customers with demands between 11

500 kW and 1,000 kW must take service on Schedules E-19 and B-19. 12

Customers with demand greater than 1,000 kW are required to take service on 13

Schedules E-20 and B-20. The basic rates for B-19 and B-20 are among 14

PG&E’s most cost-based rates as they recover costs in customer, demand (TOU 15

and non-coincident) charges and TOU energy charges. Schedules E-19V, E-19 16

and E-20 also include Option R for qualifying customers with photovoltaic (PV) 17

systems. Similarly, Schedules B-19V, B-19 and B-20 also include Option R for 18

qualifying customers with PV systems. In addition, these B Series schedules 19

include Option S, for qualifying customers with storage systems. 20

1. Overview 21

PG&E proposes the following rate design for Schedules E-19, E-19V, 22

E-20, B-19, B-19V, and B-20: 23

Retain the seasons and TOU periods adopted by D.18-08-013; 24

Except as noted below, continue the existing rate structures and rules 25

for changes between GRCs in order to implement the revenue allocation 26

results determined in this proceeding and for revenue requirement 27

changes before the next GRC Phase II proceeding to ensure rate 28

stability during the transition to rates with new TOU periods; 29

Adjust generation energy rates in the winter so that the SOP rate is not 30

less than the PCIA; and 31

Eliminate the voluntary TOU meter charges on legacy rate 32

Schedule E-19V. 33

(PG&E-3)

4-11

2. Rate Design 1

As discussed above, PG&E proposes to continue the rate design 2

established by D.18-08-013 for all rate schedules in this group. Like 3

Schedule B-10, PG&E’s proposal retains rules for changing the customer 4

charge authorized by D.18-08-013 with changes in revenue allocation in this 5

proceeding and revenue requirement changes, subject to limiting the 6

changes to customer charges at transmission voltage to ensure collection of 7

CPUC fee revenue in the applicable maximum demand charge. In addition, 8

as described in the SLP rate design section for Schedule A-6, PG&E 9

proposes to eliminate the current TOU meter charge applicable on 10

Schedule E-19V. 11

PG&E has reviewed the overall level of TOU differentials adopted by 12

D.18-08-013 relative to TOU differentials that are fully scaled based on 13

EPMC relationships. In general, PG&E believes that while the proposed 14

differentials are somewhat less than the fully EPMC scaled differentials, the 15

proposed rates are suitable for application during the transition to new TOU 16

periods in this GRC cycle. In general, PG&E recommends that the rate 17

design adopted by D.18-08-013 be continued for that purpose in this 18

proceeding. However, applying these guidelines in some cases resulted in 19

winter SOP generation rates that were less than the PCIA. In these 20

instances, PG&E proposes to adjust the winter generation energy rates so 21

that the SOP rate is not less than the PCIA. 22

Schedules E-19V, E-19 and E-20 (and the related Option R) will retain 23

the same customer charge as the B Series counterpart rate. As discussed 24

above, PG&E proposes to eliminate the voluntary TOU meter charge on 25

legacy Schedule E-19V. Rate design changes will be implemented as 26

provided in Section 3, below, until these rates are available only to solar 27

grandfathered customers. 28

3. Changes to Distribution and Generation Rates 29

As with Schedule A-10 and B-10, changes to legacy rates (E-19V, E-19, 30

E-20) and the new B Series rates (B-19V, B-19 and B-20) would use the 31

existing rules for changes between GRCs adopted by D.18-08-013 to 32

implement the revenue allocation adopted in this proceeding and for 33

revenue requirement changes before the next GRC Phase II proceeding. 34

(PG&E-3)

4-12

These rules are summarized for this customer class in Attachment A, 1

Part C. 2

F. Rate Design for Standby (Schedules S and SB) 3

PG&E provides standby service under Schedule S or Schedule SB to 4

customers whose non-utility source of generation is capable of regularly and 5

completely serving their entire electrical load. The largest portion of the load 6

currently served by PG&E under Schedule S is comprised of customers who 7

take service at transmission service voltages. Schedule S will be eliminated on 8

the date that the new Schedule SB with later TOU periods becomes mandatory. 9

Schedules S and SB include customer charges, reservation and TOU energy 10

charges, and all applicable utility charges, terms and conditions for those 11

customers whose non-utility source of generation is capable of regularly and 12

completely serving their entire electrical load. 13

A limited number of customers require “supplemental” standby service from 14

PG&E. Supplemental standby service is provided to customers who rely on 15

non-utility sources of generation for only a portion of their total load. These 16

customers pay all other charges under the terms and conditions of the 17

otherwise-applicable rate schedule. In addition, under this type of standby 18

service, the customer pays the standby reservation charge from Schedule S (or 19

Schedule SB) only for that portion of its load that is ordinarily supplied by the 20

non-utility generation resource.6 21

1. Overview 22

PG&E proposes the following rate design for Standby: 23

Retain the seasons and TOU periods adopted by D.18-08-013; 24

Revise generation reservation charges for Schedule SB to better reflect 25

the capacity cost assignment, and adjust winter generation energy 26

charges so that the winter SOP generation energy rate is not less than 27

the PCIA; and 28

Revise the method to change rates for revenue allocation and revenue 29

requirement changes in the future to adjust demand rates and energy 30

6 Demand charges billed under the terms of the otherwise-applicable rate schedule are

reduced by the amounts paid for reservation capacity under Schedule S or SB, in those instances where it is demonstrated that the maximum demand during a given billing cycle was attributable to non-operation of the customer’s generator.

(PG&E-3)

4-13

rates by an equal percent change, but implement the equal percent 1

change to energy charges on an equal ¢/kWh basis. 2

2. Rate Design 3

Standby distribution costs will be collected through a combination of 4

customer charges, energy and reservation charges. Customer charges are 5

set at the levels adopted for the otherwise applicable rate schedule. 6

Reduced customer charges, applicable to customers that pay for their 7

interconnection costs, are updated to reflect the proposed Revenue Cycle 8

Service cost and will remain unchanged until the next GRC Phase II rate 9

changes are implemented. Consistent with long established practice and to 10

maintain stable relationships across voltages, PG&E combines the billing 11

determinants and marginal costs for standby loads served at primary and 12

secondary distribution voltages before designing distribution energy and 13

reservation charges for these customers. Distribution reservation charges 14

and energy rates are changed by the equal percent change necessary to 15

recover the assigned revenue after changes to customer charges are 16

considered. However, PG&E proposes that the equal percentage change to 17

distribution energy rates will be implemented by changing each energy rate 18

on an equal ¢/kWh basis. 19

Standby generation costs will be collected through a combination of 20

energy and reservation charges. Like distribution rate design, PG&E 21

proposes to combine the billing determinants and marginal costs for standby 22

loads served at primary and secondary distribution voltages before 23

designing generation energy and reservation charges for these customers. 24

PG&E proposes to collect the energy-related share of the total generation 25

revenue assigned to Schedule SB in TOU energy charges. PG&E proposes 26

to adjust winter generation energy charges so that the SOP generation 27

energy rate is not less than the PCIA. As in past, PG&E proposes to use 28

the capacity-related share of the assigned generation revenue for Schedule 29

SB to set the generation component of the standby reservation charge. 30

Because the capacity related share of generation costs have increased 31

significantly relative to the level of those costs currently recovered in the 32

reservation charge, PG&E proposes to increase the reservation charge in 33

(PG&E-3)

4-14

this proceeding, with commensurate reductions to proposed energy rates, in 1

order to better reflect the cost of service to this class. 2

With regard to future changes to generation rates (i.e., after the 3

adjustment described above) due to changes in revenue allocation and 4

subsequent revenue requirement changes, PG&E proposes to change 5

generation reservation and energy charges by the equal percentage 6

necessary to collect the assigned revenue. However, PG&E proposes that 7

the equal percentage change to generation energy rates will be 8

implemented by changing each energy rate on an equal ¢/kWh basis. 9

3. Changes to Distribution and Generation Rates 10

Schedule SB was implemented on an opt-in basis in November 2019. 11

Schedule S will remain in effect until the new “B” series rates become 12

mandatory, which is expected in March 2021. At that time, customers taking 13

service on Schedule S will be transferred to the new Schedule SB and 14

Schedules S will be eliminated. Therefore, PG&E expects that Schedule S 15

will be eliminated before decision in this proceeding is rendered. PG&E 16

proposes that changes to rates for the new Schedule SB to implement the 17

revenue allocation adopted in this proceeding as well as for revenue 18

requirement changes will be governed by the guidelines set forth for 19

changing generation rates and distribution rates that are as described 20

above. Rules for changing distribution and generation rates, subject to the 21

initial adjustments described above, are set forth in Attachment A, Part D. 22

G. Rate Design Illustrations Requested in D.18-08-013 23

D.18-08-013 also required that PG&E file a number of illustrations of rate 24

designs to give the Commission and the other parties the fullest opportunity 25

consider other approaches to rate design.7 To this end, PG&E has provided 26

three illustrative rate designs for C&I customers. Each rate design illustration is 27

provided in Exhibit (PG&E-4), Appendix G. 28

The first illustration is required by D.18-08-013 and provides rates with TOU 29

differentials scaled to provide full EPMC differentials. Customer charges for this 30

illustration were set at the proposed levels. In the prior rate design discussion, 31

PG&E compared its rate proposal to this rate design illustration. 32

7 D.18-08-013, Ordering Paragraph (OP) 5, pp. 47-51.

(PG&E-3)

4-15

In the second illustration, PG&E has fully scaled the customer charge based 1

on EPMC while also fully scaling the TOU differentials by EPMC as shown in the 2

first illustration. PG&E is providing this illustration to show the impact on energy 3

charges if customer charges were set at full cost. 4

In the third (and last) illustration, D.18-08-013 also requires that PG&E 5

provide an illustration of rates with TOU differentials that fall in between those 6

approved by D.18-08-013 and fully EPMC scaled TOU differentials.8 Since 7

PG&E does not propose to increase customer charges to the extent shown in 8

the second illustration, PG&E has utilized fully-scaled TOU differentials provided 9

in the first illustration as one bound in this mid-point analysis. Rates were then 10

set to move half-way from the PG&E’s proposed rates, which are based on the 11

rate design adopted in D.18-08-013, and the rates provided in the first 12

illustration. This illustration provides the rates proposed to be implemented in 13

2022 for Schedule B-6. 14

Illustrative designs were prepared for Schedules B-1, B-6, B-10, B-19 15

and B-20. Where necessary, PG&E’s illustrative designs adjust the winter 16

generation energy rates so that the winter SOP rate was not less than the PCIA. 17

TABLE 4-2 ILLUSTRATIVE RATE DESIGNS

Line No. Rate Design Description 1 Illustration 1 Fully scaled TOU differentials with no change to

customer charge 2 Illustration 2 Fully scaled TOU differentials with a fully-scaled

customer charge 3 Illustration 3 Rate design established at the mid-point between the

rates adopted by D.18-08-013 and Illustration 1

H. Conclusion 18

In this chapter, PG&E has proposed rates for C&I customers that will apply 19

prior to the next GRC Phase II proceeding. PG&E’s rate design proposals seek 20

to minimize rate design changes, thereby providing a reasonable degree of 21

8 OP 5 of D.18-08-013 provides that “PG&E shall also propose an alternate set of rates

that, while not based on full EPMC scaling, are more cost based than those approved by this decision.”

(PG&E-3)

4-16

stability in rates during the period when customers are transitioned to rates with 1

new, later TOU periods. In addition, minimizing rate design changes will also 2

reduce the potential compounding effects that can be caused by making rate 3

design changes while also adjusting revenue allocation as described in 4

Chapter 2 of this exhibit. PG&E respectfully requests that the Commission 5

approve the rate design proposals contained in this chapter. 6

(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 4

ATTACHMENT A

DETAILED GUIDELINES FOR CHANGING RATES FOR

REVENUE CHANGES

(PG&E-3)

4-AtchA-i

PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 4

DETAILED GUIDELINES FOR CHANGING RATES FOR REVENUE CHANGES

TABLE OF CONTENTS

A. Introduction ....................................................................................................... 4-1

1. Distribution Rate Design ............................................................................ 4-1

2. Generation Rate Design ............................................................................. 4-1

B. Schedules A-10 and B-10 ................................................................................. 4-2

1. Distribution Rate Design ............................................................................ 4-2

2. Generation Rate Design ............................................................................. 4-2

C. Schedules E-19V, E-19, E-20, B-19V, B-19, and B-20 ..................................... 4-3

1. Distribution Rate Design ............................................................................ 4-3

2. Generation Rate Design ............................................................................. 4-4

D. Schedule SB ..................................................................................................... 4-4

1. Distribution Rate Design ............................................................................ 4-4

2. Generation Rate Design ............................................................................. 4-5

(PG&E-3)

4-AtchA-1

PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 4 2

DETAILED GUIDELINES FOR CHANGING RATES FOR 3

REVENUE CHANGES 4

A. Introduction 5

Changes to Small Light and Power legacy rates and the B Series rates will 6

continue to utilize the existing rules for changes between General Rate Cases 7

(GRC) adopted by Decision (D.)18-08-013 in order to implement the revenue 8

allocation adopted in this proceeding as well as for revenue requirement 9

changes before the next GRC Phase II proceeding. Rules for changes to 10

distribution and generation rates are set forth below. 11

1. Distribution Rate Design 12

The distribution revenue requirement will be allocated to each rate 13

schedule as provided in Exhibit (PG&E-3), Chapter 2. Distribution rates will 14

then be designed to collect the allocated revenue. Pacific Gas and Electric 15

Company (PG&E) proposes to retain the approved customer charges until 16

the levels of those charges are revisited in its 2023 GRC Phase II. With the 17

exception of the proposed change to increase the Time-of-Use (TOU) 18

differentials for Schedule B-6 in 2022, demand and energy charges each will 19

be designed to change by the same percentage change in rate necessary to 20

collect the required revenue. However, the change in energy charges will 21

be determined by the equal cents per kilowatt-hour (kWh) adder that is 22

required to collect the necessary change in energy charge revenue. This 23

approach to setting the distribution energy charges will ensure that the 24

differential in rates between seasons and TOU periods remains the same on 25

a cents per kWh basis. 26

2. Generation Rate Design 27

The generation revenue requirement will be allocated to each rate 28

schedule as provided in Exhibit (PG&E-3), Chapter 2. Generation rates will 29

then be designed to collect the allocated revenue. With the exception of the 30

proposed change to increase the TOU differentials for Schedule B-6 in 31

2022, demand and energy charges will be designed to each change by the 32

same percentage amount as necessary to collect the required revenue. 33

(PG&E-3)

4-AtchA-2

However, the change in energy charges will be determined by the equal 1

cents per kWh adder that is required to collect the necessary change in 2

energy charge revenue. This approach to setting the generation energy 3

charges will ensure that the differential in rates between seasons and TOU 4

periods remains the same on a cents per kWh basis. 5

B. Schedules A-10 and B-10 6

Changes to legacy rates (A-10) and the B Series rates (B-10) will continue 7

to utilize the existing rules for changes between GRCs adopted by D.18-08-013 8

in order to implement the revenue allocation adopted in this proceeding as well 9

as for revenue requirement changes before the next GRC Phase II proceeding. 10

Rules for changing distribution and generation rates are set forth below. 11

1. Distribution Rate Design 12

The distribution revenue requirement will be allocated to each rate 13

schedule as provided in Exhibit (PG&E-3), Chapter 2. Distribution rates will 14

then be designed to collect the allocated revenue. For Schedules B-10 and 15

A-10, customer charges, demand charges, and energy charges will be 16

designed to change by the same percentage change in rate necessary to 17

collect the required revenue. However, the change to energy charges will 18

be determined by the equal cents per kWh adder required to collect the 19

necessary change in energy charge revenue. This approach to setting the 20

distribution energy charges for Schedules A-10 and B-10 will ensure that the 21

differential in energy rates between seasons and TOU periods remains the 22

same on a cents per kWh basis for these schedules. 23

2. Generation Rate Design 24

The generation revenue requirement will be allocated to each rate 25

schedule as provided in Exhibit (PG&E-3), Chapter 2. Generation rates will 26

then be designed to collect the allocated revenue. Demand and energy 27

charges will be designed to each change by the same percentage change in 28

rate necessary to collect the required revenue for Schedules A-10 and B-10. 29

However, the change in energy rates will be determined by the equal cents 30

per kWh adder required to collect the necessary change in energy charge 31

revenue. This approach to setting the generation energy charges for 32

(PG&E-3)

4-AtchA-3

Schedules A-10 and B-10 will ensure that the differential in rates between 1

seasons and TOU periods remains the same on a cents per kWh basis. 2

C. Schedules E-19V, E-19, E-20, B-19V, B-19, and B-20 3

Changes to legacy rates (E-19V, E-19, E-20) and the B Series rates (B-19V, 4

B-19 and B-20) will continue to utilize the existing rules for changes between 5

GRCs adopted by D.18-08-013 in order to implement the revenue allocation 6

adopted in this proceeding as well as for revenue requirement changes before 7

the next GRC Phase II proceeding. Rules for changing distribution and 8

generation rates are set forth below. 9

1. Distribution Rate Design 10

The distribution revenue requirement will be allocated to each rate 11

schedule as provided in Exhibit (PG&E-3), Chapter 2. Distribution rates will 12

then be designed to collect the allocated revenue. For Schedules E-19V 13

and B-19V, the customer charge will be set to the customer charge for 14

Schedules A-10 and B-10. All remaining customer charges and demand 15

charges on these schedules will be changed by an equal percentage 16

change to collect the required revenue. Customer charge changes resulting 17

from the method described above for transmission service voltages will be 18

limited to ensure that the residual distribution maximum demand charge 19

collects the revenue associated with the California Public Utilities 20

Commission Fee. 21

For Option R, distribution rates will be designed by converting 22

75 percent of the distribution revenue derived from peak and part-peak 23

distribution demand charges to energy charges. Energy charges will be 24

designed to change by the equal cents per kWh adder required to collect the 25

necessary change in energy charge revenue. This approach to setting the 26

distribution energy charges for Option R will ensure that the differential in 27

energy rates between seasons and TOU periods remains the same on a 28

cents per kWh basis. 29

Option S will begin from the Option R design for B-19V, B-19, and B-20 30

only. Revenue associated with the non-coincident demand charges for 31

Option R will be converted to a daily demand charge applicable in the peak 32

period (80 percent share), and to a special non-coincident demand charge 33

(PG&E-3)

4-AtchA-4

applicable in all hours except 9 a.m. to 2 p.m. (20 percent share). Revenue 1

associated with the peak and partial peak demand charges on Option R will 2

be converted to peak and partial-peak daily demand charges. 3

2. Generation Rate Design 4

The generation revenue requirement will be allocated to each rate 5

schedule as provided in Exhibit (PG&E-3), Chapter 2. Generation rates will 6

then be designed to collect the allocated revenue. Demand and energy 7

charges for schedules E-19V, E-19, E-20, B-19V, B-19, and B-20 will be 8

designed to each change by the same percentage change in rate necessary 9

to collect the required revenue. When necessary, however, winter 10

generation energy rates will be adjusted to ensure that the Super Off Peak 11

(SOP) rate is not less than the Power Charge Indifference Adjustment 12

(PCIA). 13

For Option R, generation rates will be designed by converting 14

100 percent of the generation revenue derived from peak and part-peak 15

generation demand charges and converting that revenue to energy charges. 16

Energy charges will be designed to change by the equal cents per kWh 17

adder required to collect the necessary change in energy charge revenue. 18

This approach to setting the generation energy charges for Option R will 19

ensure that the differential in energy rates between seasons and TOU 20

periods remains the same on a cents per kWh basis. Generation rates for 21

Option S will be the same as the generation rates for Option R for 22

Schedules B-19V, B-19 and B-20. 23

D. Schedule SB 24

Changes to Schedule SB will utilize the following rules to implement the 25

revenue allocation adopted in this proceeding as well as for revenue 26

requirement changes before the next GRC Phase II proceeding. Rules for 27

changing distribution and generation rates, after the initial rate adjustments 28

described in Exhibit (PG&E-3), Chapter 4 are implemented, are set forth below. 29

1. Distribution Rate Design 30

The distribution revenue requirement will be allocated to each rate 31

schedule as provided in Exhibit (PG&E-3), Chapter 2. Distribution rates will 32

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4-AtchA-5

then be designed to collect the allocated revenue. Customer charges will be 1

set based on the rate for the otherwise applicable schedule. 2

For Schedule SB, reservation and energy charges will be designed to 3

change by the same percentage change in rate necessary to collect the 4

required revenue. However, the change to energy charges will be 5

determined by the equal cents per kWh adder required to collect the 6

necessary change in energy charge revenue. This approach to setting the 7

distribution energy charges for Schedule SB will ensure that the differential 8

in energy rates between seasons and TOU periods remains the same on a 9

cents per kWh basis for these schedules. 10

2. Generation Rate Design 11

The generation revenue requirement will be allocated to each rate 12

schedule as provided in Exhibit (PG&E-3), Chapter 2. Generation rates will 13

then be designed to collect the allocated revenue. Reservation and energy 14

charges will be designed to change by the same percentage change in rate 15

necessary to collect the required revenue. However, the change to energy 16

charges will be determined by the equal cents per kWh adder required to 17

collect the necessary change in energy charge revenue. This approach to 18

setting the generation energy charges for Schedule SB will ensure that the 19

differential in energy rates between seasons and TOU periods remains the 20

same on a cents per kWh basis for these schedules. When necessary, 21

however, winter generation energy rates will be adjusted to ensure that the 22

SOP rate is not less than the PCIA. 23

(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 5

AGRICULTURAL RATE DESIGN

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PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 5

AGRICULTURAL RATE DESIGN

TABLE OF CONTENTS

A. Introduction ....................................................................................................... 5-1

B. Background ...................................................................................................... 5-3

1. Transition to New TOU Periods ................................................................. 5-3

2. Distribution and Generation Cost of Service Principles .............................. 5-3

3. Other Rate Design Principles ..................................................................... 5-3

C. AG Rate Design ............................................................................................... 5-4

1. Overview .................................................................................................... 5-4

2. Distribution Rate Design ............................................................................ 5-5

3. Generation Rate Design ............................................................................. 5-6

4. Proposed Rates ......................................................................................... 5-7

5. Eliminate Voluntary TOU Meter Charges ................................................... 5-7

6. Optimal Billing Period Program .................................................................. 5-8

7. Rates for Solar Grandfathered Customers ................................................. 5-8

8. AG Data Reporting Requirements ............................................................. 5-9

9. Illustrative AG Rate Designs ...................................................................... 5-9

D. Conclusion ...................................................................................................... 5-11

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PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 5 2

AGRICULTURAL RATE DESIGN 3

A. Introduction 4

In this chapter, Pacific Gas and Electric Company (PG&E) proposes rates 5

for the Agricultural (AG) class of customers. The AG class includes Small AG 6

(Schedules AG-A1, AG-A2, and AG-FA), Medium AG (Schedules AG-B and 7

AG-FB), and Large AG (Schedules AG-C and AG-FC). Six of these seven rate 8

schedules were adopted by the California Public Utilities Commission 9

(Commission) in Decision (D.) 18-08-013 in PG&E’s 2017 General Rate Case 10

(GRC) Phase II case. Modifications to all six of those rates, as well as the 11

addition of new Schedule AG-A2 for higher load factor small AG customers, 12

were also adopted in PG&E’s 2019 Rate Design Window (RDW) proceeding in 13

D.19-05-010. 14

The default AG rates are Time-of-Use (TOU) Schedules AG-A1, AG-A2, 15

AG-B, and AG-C. Flexible off-peak hours are available on a voluntary opt-in 16

basis on TOU Schedule AG-F, on options AG-FA, AG-FB, and AG-FC. All of the 17

new AG TOU rates have on-peak hours of 5-8 p.m., with no partial-peak or 18

super-off-peak periods, to respond to the needs of AG customers for rates that 19

are simple to understand, and that better reflect the logistical and operational 20

needs of farming and other AG operations.1 21

Rate design for these AG schedules includes rate components for 22

transmission, distribution, generation, Public Purpose Programs (PPP), Nuclear 23

Decommissioning, Department of Water Resources Bond Charge, New System 24

Generation Charges, the Energy Cost Recovery Amount, and the Power Charge 25

Indifference Adjustment. In this proceeding, PG&E is proposing changes to AG 26

generation, distribution and PPP revenue allocation and rate design. PG&E is 27

not making any proposals for revenue allocation and rate design for other 28

components of AG rates. Accordingly, PG&E’s current approach to revenue 29

allocation and rate design for these components is set forth in Chapter 1, 30

“Revenue Allocation and Rate Design Introduction.” Generation, distribution, 31

1 D.18-08-013, pp. 35-36, 87-88.

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and PPP revenue allocation, as well as PPP rate design,2 is addressed in 1

Chapter 2. AG rate design for generation and distribution is set forth in this 2

chapter. 3

As discussed in Exhibit (PG&E-3), Chapter 1, a key objective of PG&E’s AG 4

rate design proposal is to retain the rate designs adopted in PG&E’s 2017 GRC 5

Phase II (D.18-08-013) and 2019 RDW (D.19-05-010) proceedings because AG 6

customers are being transitioned to rates with new TOU periods. To that end, 7

PG&E’s generation and distribution AG rate proposals in this proceeding 8

include: 9

For the revenue allocation change in this proceeding, as well as revenue 10

requirement changes for rate changes between GRCs, continue to apply the 11

rules for rate changes between GRCs adopted by D.18-08-013, but revise 12

for the initial and each subsequent electric rate change as necessary to 13

preserve AG intra-class rate schedule relationships; and 14

Eliminate any remaining instances of voluntary TOU meter charges, as 15

these charges are no longer appropriate. 16

Attachment A to this chapter presents the proposed AG rates that PG&E is 17

sponsoring for adoption in this chapter. In addition, in this chapter, PG&E also 18

presents and discusses proposals for illustrative rate designs that D.18-08-0133 19

required be presented in this proceeding. These illustrative rates are presented 20

in Exhibit (PG&E-4), Appendix H. 21

The remainder of this chapter is organized as follows: 22

Section B – Background 23

Section C – AG Rate Design 24

Section D – Conclusion 25

Various other Appendices in Exhibit (PG&E-4) present the following 26

information. Appendix A provides recorded 2017 to 2018 data for the customer 27

classes presented in this chapter. Appendix B presents PG&E’s proposed 28

revenue allocation results from Chapter 2. Appendix C, “Present and Proposed 29

Rates,” contains PG&E’s present and proposed total and unbundled rates for the 30

2 PPP rates for the agricultural class are designed in accordance with the guidelines

described in Chapter 1, using the revenue allocation provided in Chapter 2. 3 D.18-08-013, p. 51, and Ordering Paragraph (OP) 5.

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AG customer class. Appendix D, “Illustrative Bill Impacts,” presents the bill 1

comparison impacts of PG&E’s proposals on AG customers. 2

B. Background 3

1. Transition to New TOU Periods 4

Under the plan adopted in D.18-08-013, rates with new TOU periods will 5

become available on an opt-in basis for AG customers in the first quarter of 6

2020, by no later than March 2020. Then, on March 1, 2021, PG&E will 7

begin the mandatory transition of all remaining AG customers to the rates 8

with new TOU periods. From the date when the rates with new TOU periods 9

become available on an opt-in basis, until March 1, 2021, PG&E will retain 10

all AG rates on both the old TOU structure (referred to herein as ‘legacy 11

rates’) as well as the new TOU structures (or rates with new TOU periods). 12

Also, beginning on March 1, 2021, rates with grandfathered legacy TOU 13

periods will become available for solar customers that have met the 14

grandfathering requirements under D.17-01-006. PG&E is working toward 15

these deadlines and currently expects to meet this schedule. 16

2. Distribution and Generation Cost of Service Principles 17

PG&E’s cost of service considerations for distribution and generation 18

were described in Chapter 1. While PG&E’s primary proposal in this 19

proceeding is to continue the current approach to changing rates and to 20

make very few changes to the AG rate relationships established by 21

D.18-08-013 and D.19-05-010, PG&E has utilized the rate principles 22

articulated in Chapter 1 to prepare proposed and illustrative compliance 23

rates which are discussed below. 24

3. Other Rate Design Principles 25

In addition to cost of service principles, PG&E’s rate design 26

recommendations also consider other rate design objectives. As discussed 27

in Chapter 1, they include balancing cost of service considerations with rates 28

that offer stability, are understandable and transparent, offer meaningful 29

rates to customers and are practical to implement. In this 2020 GRC 30

Phase II, PG&E believes that stability is extremely important due to the 31

timing of this case in relation to the initial opt-in roll out and mandatory 32

transition of customers to rates with new TOU periods. 33

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C. AG Rate Design 1

As noted above, the AG class includes new default Schedules AG-A1, 2

AG-A2, AG-B and AG-C, and voluntary opt-in Schedules AG-FA, AG-FB, and 3

AG-FC.4 The new AG rates are based on a threshold of 35 kilowatts (kW) to 4

separate smaller AG-A customers from larger AG-B and AG-C customers. 5

In addition, the “legacy” AG rates include small customer Schedules AG-1A, 6

AG-4A, AG-5A, AG-RA, and AG-VA; medium customer Schedules AG-1B, 7

AG-4B, AG-4C, AG-RB, and AG-VB; and large customer Schedules AG-5B and 8

AG-5C.5 PG&E’s legacy boundary between the small AG class and the medium 9

to large AG class is 35 horsepower (hp), or 15 hp for customers with multiple 10

pumps. D.18-08-013 established rules through the end of 2023 governing the 11

rate design for legacy AG rates, for qualifying grandfathered solar or other 12

customers, and therefore is not addressed in detail here. In this proceeding, 13

PG&E proposes to retain the current legacy and new eligibility thresholds within 14

the AG customer class. 15

1. Overview 16

PG&E proposes the following rate design for the AG class: 17

Continue the existing rate structures and rules for changes between 18

GRCs, but revise for the initial and each subsequent electric rate 19

change as necessary to preserve AG intra-class rate schedule 20

relationships, in order to implement the revenue allocation results 21

determined in this proceeding, and for revenue requirement changes 22

before the next GRC Phase II proceeding, to support rate stability during 23

the transition to rates with new TOU periods; and 24

4 In December 2019, PG&E plans to submit by Advice Letter (AL) proposed tariff sheets

and illustrative rates for new Schedule AG, and for new Schedule AG-F, to be effective beginning with the March 1, 2020 voluntary opt-in date, to specify the tariff terms and conditions of service and rates for all four main new default Schedule AG Agricultural electric rate options, as well as the three rate options available under voluntary Schedule AG-F. (See AL 5708-E, submitted December 9, 2019, approved by Energy Division on January 10, 2020.).

5 In December 2019, PG&E plans to submit a second AL addressing proposed tariff sheet revisions for all twelve legacy Agricultural rate schedules, to be effective beginning with the March 1, 2020 voluntary opt-in date, to specify the modifications to legacy tariffs necessary to describe the transition from legacy to new rates, and all other applicable terms and conditions of service. (See AL 5709-E, submitted December 9, 2019, approved by Energy Division on January 10, 2020.).

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Eliminate voluntary TOU meter charges. 1

2. Distribution Rate Design 2

In D.18-08-013, OP 27 stated as follows: 3

PG&E must propose in its next GRC Phase II application agricultural 4 rates (along with all other non-residential Time-of-Use rates) that better 5 reflect time-differentiation of marginal distribution costs, and contain 6 peak-to-off-peak price differentials that encourage agricultural 7 customers to invest in energy management technology and practices 8 that allow them to respond to peak price signals. 9

However, PG&E already complied with the above order through the rate 10

design modifications proposed and approved in PG&E’s 2019 RDW, as 11

adopted in D.19-05-010. 12

Except as noted below, changes to legacy rates and to rates with new 13

TOU periods will be governed by the rules for rate changes between GRCs 14

as determined by D.18-08-013, as applied to the AG rates adopted in 15

D.19-05-010. Changes to distribution rates are set forth below. Revenue 16

requirements will be allocated to each rate schedule as provided in 17

Chapters 1 and 2. 18

AG fixed monthly customer charges will not change for legacy rates, or 19

from the levels initially set for rates with new TOU periods as of the date 20

when rates with new TOU periods become available on an opt-in basis. 21

Customer charges will not change from those levels until the 2023 GRC 22

Phase II. 23

Demand and energy charges each will be designed to change by the 24

same percentage change in rates necessary to collect the required revenue. 25

Demand charges will each be changed by the same percentage, and energy 26

charges in total will also be changed by the same percentage amount, 27

except as required to recover Demand Charge Rate Limiter (DCRL) 28

shortfalls.6 PG&E has re-estimated the revenue shortfalls attributable to the 29

adopted 50 cent per kilowatt-hour (kWh) DCRL, and proposes to recover the 30

shortfall through an equal cent per kWh adder to all Schedule AG-C TOU 31

distribution energy charges in both seasons, per the adopted methodology. 32

6 The DCRL applies only to default Schedule AG-C. As adopted in D.18-08-013 and

D.19-05-010, a 50 cent-per-kWh charge shall limit the monthly sum of demand charges and energy charges, excluding the fixed monthly customer charge.

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However, the change in distribution energy charges will be determined 1

by whatever equal-cents-per-kWh adder is required to collect the necessary 2

change in distribution energy charge revenue. This approach to setting the 3

distribution energy charges will ensure that the differential in rates between 4

seasons and TOU periods remains the same on a cents-per-kWh basis. 5

For schedules that are designed together (such as schedules that are 6

designed on a revenue neutral basis, or where rate schedule relationships 7

are to be preserved), the system average percentage change by function 8

will be applied to the combined rate design group. For example, the 9

percentage change applied to the allocated distribution revenue on AG-B 10

and AG-C was set to the same percentage,7 in order to preserve the 11

traditional 1,500 annual break-even pumping hours where the AG rates for 12

larger customers are generally better for customers than the rates for 13

medium customers. 14

3. Generation Rate Design 15

Except as noted below, changes to legacy rates and to rates with new 16

TOU periods will be governed by the rules for rate changes between GRCs 17

as determined by D.18-08-013.8 Rates will be designed to collect the 18

generation revenue requirement allocated to each rate schedule as provided 19

in Chapters 1 and 2. Changes to generation rates are set forth below. 20

Demand and energy charges for the generation component of rates will 21

be designed to each change by the same percentage amount as necessary 22

to collect the required allocated generation revenue. That is, generation 23

demand charges will be changed by the same percentage and generation 24

7 For the initial rate change to implement 2020 GRC Phase II rates, the percentage

change to AG-B was set approximately two to three percentage points higher than the percentage change to AG-C, for distribution, and for generation, in order to offset the impact of the DCRL equal-cent-per-kWh adder on AG-C distribution and total energy charges and preserve 1,500 break-even pumping hours. Going forward with interim GRC rate changes, the percentage change on distribution, and the percentage change on generation, will be equivalent across AG-B and AG-C.

8 D.18-08-013, Supplemental Settlement Agreement in PG&E’s GRC Phase II (Application 16-06-013) on Agricultural Rate Design, Term V.H., Rate Changes Between GRC Phase II Proceedings, pp. A-13 to A-14, as well as Settlement Agreement in Phase II of PG&E’s 2017 GRC on Marginal Cost and Revenue Allocation Issues, Term VIII. 3., Rate Changes Between GRCs, pp. 16-19.

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energy charges in total will also be changed by the same percentage 1

amount. 2

However, the change in generation energy charges will be determined 3

by whatever equal-cents-per-kWh adder that is required to collect the 4

necessary change in generation energy charge revenue. This approach to 5

setting the generation energy charges will ensure that the differential in 6

rates between seasons and TOU periods remains the same on a 7

cents-per-kWh basis. 8

For schedules that are designed together (such as schedules that are 9

designed on a revenue neutral basis, or where rate schedule relationships 10

are to be preserved), the system average percentage change by function 11

will be applied to the combined rate design group. As with distribution, the 12

percentage change applied to the allocated generation revenue on AG-B 13

and AG-C was set to the same percentage, in order to preserve the 14

traditional 1,500 annual break-even pumping hours where AG-C is generally 15

better for customers than AG-B. 16

4. Proposed Rates 17

As noted above, PG&E’s proposal is generally to minimize the changes 18

to AG rate design that were approved by D.18-08-013 and D.19-05-010. 19

Appendix C provides illustrative proposed AG rates under the revenue 20

allocation and rate design that PG&E is sponsoring for implementation. At 21

the point in time that this 2020 GRC Phase II proceeding is implemented in 22

rates, the new mandatory AG rates scheduled to be implemented in 23

March 2021 will have been in place for less than one year. This strongly 24

suggests that PG&E’s proposal to carry forward the AG rate designs 25

adopted in PG&E’s 2019 RDW with as little revision as possible is advisable 26

to smooth customer transitions to the new AG rates with later TOU hours. 27

5. Eliminate Voluntary TOU Meter Charges 28

PG&E’s current legacy AG rates may still retain varying levels of 29

ongoing monthly TOU meter charges for those relatively few meter sites 30

where an interval meter has not been installed. In legacy AG tariffs, AG-A 31

rates carry a $6.80 per month “TOU Meter Charge” if applicable, with a 32

lower charge of only $2.00 per month for related AG-D rates for those AG-A 33

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5-8

customers who paid an up-front “TOU Meter Installation Charge” to cover 1

the incremental cost of a TOU meter over a standard non-TOU meter. 2

Similarly, legacy AG-B and AG-C rates carry a $6.00 per month TOU Meter 3

Charge, if applicable, and a lower ongoing AG-E or AG-F monthly TOU 4

Meter Charge of $1.20 per month. 5

The lower ongoing Monthly TOU Meter Charge was designed to cover 6

the prior incremental costs of meter reading, billing, and education and 7

outreach associated with the earlier days of metering and billing of voluntary 8

TOU service. PG&E proposes to eliminate these incremental ongoing 9

legacy TOU meter charges as obsolete, since TOU service is now the 10

mandatory or standard basis for service. 11

6. Optimal Billing Period Program 12

PG&E proposes no changes to the modifications to the Optimal Billing 13

Period Program revisions adopted in D.18-08-013. Those revisions left the 14

program cap of 50 participants in place, retained the option on 15

Schedule AG-5C until AG-5C expires, transferred AG eligibility to the new 16

AG-C, expanded the program to Schedule E-19 above 500 kW and to 17

Schedule E-20, and expanded eligibility to direct access and community 18

choice aggregation. D.18-08-013 adopted revisions which established that 19

36 of the 50 participation slots would be assigned to AG customers, and 20

14 to medium and large Commercial or Industrial customers.9 21

7. Rates for Solar Grandfathered Customers 22

Legacy rates for qualifying solar grandfathered customers were subject 23

to rate transition plans established in D.18-08-013 through the end of 2023. 24

While this 2020 GRC Phase II proceeding may update the cost-basis for 25

rates for solar grandfathered customers that were not subject to transition 26

plans adopted by D.18-08-013, there were none in the AG class. Instead, 27

9 As of late October 2019, there were 31 Agricultural customers, and seven Commercial

and Industrial customers, participating in the Optimal Billing Period program. Pursuant to D.18-08-013, PG&E filed AL 5470-E to expand program eligibility to qualifying E-19 and E-20 Commercial and Industrial customers, and to Direct Access and Community Choice Aggregation (CCA) customers, effective February 9, 2019. Subsequently, seven Commercial customers joined the program, five of whom were CCA customers. All seven of the new commercial participants appear to be involved in fruit or vegetable canning operations.

(PG&E-3)

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for all legacy TOU AG rates, D.18-08-013 adopted a phase-in plan to flatten 1

the on-peak versus off-peak rate differentials applicable under the old legacy 2

TOU periods and seasons. As a result, PG&E proposes to simply 3

implement the solar grandfather rate designs specified in D.18-08-013. 4

However, revenue allocation changes will still apply to legacy grandfathered 5

AG rates. The associated legacy schedule level revenue allocation 6

percentage changes have been set to the same schedule level revenue 7

allocation percentage changes as the new AG TOU rates to which each 8

legacy AG rate schedule maps, in order to preserve rate schedule 9

relationships. 10

8. AG Data Reporting Requirements 11

In D.18-08-013, the Settlement Agreement on Marginal Cost and 12

Revenue Allocation, Attachment 2, “Agricultural Data Reporting 13

Requirements,” Section D, page 5, paragraph 3, states as follows: 14

3) Annual reports for the Tracking period from 2016 through the latest 15 year available (likely to be 2017) will be provided as part of PG&E’s 16 2020 GRC Phase II application. 17

The various reporting requirements set forth in Attachment 2 were quite 18

voluminous, and include many reports. Further reports covering 2019 data 19

will also be required during 2020. However, for inclusion with this 2020 20

GRC Phase II application, the latest year available and applicable at the 21

time this testimony was prepared covers AG data reporting requirements 22

through 2018. By agreement with Agricultural Energy Consumers 23

Association and California Farm Bureau Federation, PG&E is providing 24

copies of these reports as part of the workpapers supporting this application. 25

On March 30, 2020, PG&E separately provided AG data reporting 26

requirements covering 2019 data. A final set of data due August 1, 2020 will 27

cover load data for 2019 and will complete compliance with these 2017 GRC 28

Phase II AG data reporting requirements. 29

9. Illustrative AG Rate Designs 30

D.18-08-013 required that a number of illustrative AG rate designs be 31

provided in this proceeding to give the Commission and the other parties the 32

fullest opportunity to consider other approaches to rate design, as follows: 33

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PG&E shall propose more cost-based rates, based on full equal percent 1 of marginal cost (EPMC) scaling of all marginal cost components, for its 2 non-residential Time-of-Use (TOU) customers in its next GRC Phase II 3 proceeding. PG&E shall also propose an alternative set of rates that, 4 while not based on full EPMC scaling, are more cost-based than those 5 approved by this decision. (D.18-08-013, OP 5.) 6

To this end, PG&E has provided the following illustrative cases in 7

Appendix H, “Illustrative Rate Designs for Agricultural Customers”: 8

a) Illustrative Full EPMC Rates per D.18-08-013: Traditional full EPMC 9

rates based on full scaling of applicable distribution and generation 10

marginal cost revenues, as discussed at pages 12 through 55 of 11

D.18-08-013, including setting customer charges at higher full EPMC 12

levels. 13

b) Illustrative Full EPMC Rates, but With Customer Charges Set at 14

PG&E’s Sponsored Proposed Lower Levels, Below Full EPMC 15

Levels: Because higher full EPMC customer charges are not realistic 16

for fixed monthly customer charges, PG&E has instead set illustrative 17

customer charges at the same level as in PG&E’s main proposal. This 18

also better facilitates comparisons across the rate design scenarios. 19

c) Partial EPMC Rates per D.18-08-013: While not based on full EPMC 20

scaling, PG&E has instead used unscaled Marginal Costs to develop 21

the final rate design scenario ordered by D.18-08-013, again retaining 22

customer charges only at PG&E’s sponsored proposed lower levels. 23

Comparison of PG&E’s sponsored proposed rates to these three above 24

illustrative compliance sets of rates shows varying levels of customer 25

charges, demand charges, and TOU price differentials. In the full EPMC 26

scenario, customer charges set at full EPMC levels would result in 27

differential bill comparison results and would not be acceptable for reasons 28

of rate stability stated herein. Further, as stated earlier, at the time this 2020 29

GRC Phase II proceeding is implemented in rates, the new mandatory AG 30

rates scheduled to be implemented in March 2021 will have been in place 31

for less than one year. This strongly suggests that PG&E’s proposal to carry 32

forward the AG rate designs adopted in PG&E’s 2019 RDW with as little 33

revision as possible is advisable, to smooth customer transitions to the new 34

AG rates with later TOU hours. Therefore, PG&E does not propose that any 35

of the three sets of illustrative rates be adopted. However, they are provided 36

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as a compliance item for the convenience and reference of the Commission 1

and parties. 2

D. Conclusion 3

In this chapter, PG&E has presented the background supporting the new AG 4

rates with later TOU hours adopted in PG&E’s 2017 GRC Phase II and 2019 5

RDW proceedings. PG&E proposes to preserve the AG rate design adopted in 6

the GRC as modified by the 2019 RDW by applying “interim GRC rules” to the 7

slate of new default and voluntary AG rates adopted in the 2019 RDW, as 8

modified to preserve intra-class rate schedule relationships, such as the 1,500 9

pumping hour break-even level, where AG-C is generally better for customers 10

than AG-B. This will stabilize the rates with later TOU hours as AG customers 11

adapt to the new later TOU hours of 5-8 p.m. that will become mandatory 12

beginning in March 2021. Changes to grandfathered legacy rates for solar 13

customers will occur under the rules adopted in D.18-08-013, but are subject to 14

updated revenue allocation to preserve legacy and new schedule level 15

percentage changes. 16

In addition, PG&E provided a compliance showing to illustrate rates under 17

alternative rate design approaches. However, PG&E does not support the 18

adoption of these alternative rate designs. Finally, PG&E proposes to eliminate 19

obsolete voluntary TOU meter charges, and proposes no changes to the 20

Optimal Billing Period Program. 21

(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 6

STREETLIGHTING RATE DESIGN

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6-i

PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 6

STREETLIGHTING RATE DESIGN

TABLE OF CONTENTS

A. Introduction ....................................................................................................... 6-1

B. Background ...................................................................................................... 6-2

C. Non-Energy Facility Charge Calculation for Schedules LS-1, LS-2, OL-1, and CCSF Streetlights ...................................................................................... 6-3

1. Universal Charge ....................................................................................... 6-4

a. O&M Expense ..................................................................................... 6-4

b. Customer Accounts Expense .............................................................. 6-4

c. A&G Expenses .................................................................................... 6-5

2. Remaining O&M Expense Charge ............................................................. 6-5

3. Plant-Related Charge ................................................................................. 6-5

a. Plant Revenue Requirements .............................................................. 6-5

b. Replacement Costs ............................................................................. 6-6

c. Plant Revenue Requirement Allocation ............................................... 6-7

D. Energy Charge and Total Streetlight Rates for Schedules LS-1, LS-2 and OL-1 .......................................................................................................... 6-7

E. Rate Design for Schedule LS-3 ........................................................................ 6-7

F. City and County of San Francisco Streetlight Rates ......................................... 6-8

G. LED Streetlight Conversion Program................................................................ 6-8

1. Non-Decorative Lamps .............................................................................. 6-8

2. Decorative Lamps ...................................................................................... 6-9

H. Network-Controlled Dimmable Streetlight ......................................................... 6-9

1. Pilot Program ............................................................................................. 6-9

2. Rate Design for a Fully-Integrated Metered and Billing Solution for Dimmable Streetlights .............................................................................. 6-11

I. Conclusion ...................................................................................................... 6-12

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PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 6 2

STREETLIGHTING RATE DESIGN 3

A. Introduction 4

This chapter presents Pacific Gas and Electric Company’s (PG&E) 5

2020 General Rate Case (GRC) Phase II rate design proposals for the 6

Streetlight customer class. Rate design for the Streetlight customer class 7

includes rate components for transmission, distribution (including facility 8

charges), generation, Public Purpose Programs (PPP), Competition Transition 9

Charges, Nuclear Decommissioning, Department of Water Resources Bond 10

Charge, New System Generation Charges, the Energy Cost Recovery Amount, 11

and the Power Charge Indifference Adjustment. In this proceeding, PG&E is 12

proposing changes to generation, distribution and PPP revenue allocation and 13

rate design. PG&E is not making any proposals for revenue allocation and rate 14

design for other components of streetlight rates. Accordingly, PG&E’s current 15

approach to revenue allocation and rate design for these components is set forth 16

in Chapter 1, “Revenue Allocation and Rate Design Introduction.” Generation, 17

distribution and PPP revenue allocation, as well as PPP rate design,1 is 18

described in Exhibit (PG&E-3), Chapter 2. 19

PG&E’s updates to streetlight rate design proposals for the Streetlight 20

customer class are described in the following testimony and include adjustments 21

to facility charge rates to reflect updated costs as well as determination of the 22

total monthly streetlight charges. Consistent with PG&E’s Revenue Allocation 23

proposal in Chapter 2, PG&E’s goal is to transition allocations to full cost of 24

service over a period of six years. Accordingly, PG&E proposes to adjust the 25

facility charge 1/6th the way towards the full revenue requirement each year for 26

the next three years. PG&E would then reassess costs in its 2023 GRC 27

Phase II and propose the continuation of its transition plan in that proceeding. 28

1 PPP rates for the streetlighting customers are designed in accordance with the

guidelines described in Chapter 1 using the revenue allocation provided in Chapter 2.

(PG&E-3)

6-2

The remainder of this chapter is organized as follows: 1

Section B – Background 2

Section C – Non-Energy Facility Charge Calculation for Schedules LS-1, 3

LS-2, OL-1, and CCSF Streetlights 4

Section D – Energy Charge and Total Streetlight Rates for Schedules LS-1, 5

LS-2, and OL-1 6

Section E – Rate Design for Schedule LS-3 7

Section F – City and County of San Francisco (CCSF) Streetlight Rates 8

Section G – Light-Emitting Diode (LED) Streetlight Conversion Program 9

Section H – Network-Controlled Dimmable Streetlight 10

Section I – Conclusion 11

B. Background 12

In this chapter, PG&E addresses rate design for Schedules LS-1, LS-2, 13

LS-3, OL-1, and CCSF streetlights. Schedules LS-1 and LS-2 provide options 14

for illuminating public streets, highways, and other outdoor ways and places and 15

are designed as a fixed monthly charge. Schedule OL-1 is also designed as a 16

fixed charge per month for private outdoor lighting. PG&E also develops fixed 17

monthly charges for CCSF’s streetlights. Schedule LS-3, however, is a metered 18

schedule with a customer charge and an energy rate that does not vary by time 19

of day or season. 20

Schedules LS-1, LS-2, OL-1 and CCSF streetlights include a fixed monthly 21

charge per lamp based on the most common type and size of lamp within each 22

rate schedule and the type of service provided by PG&E (e.g., LS-1A, LS-1C, 23

etc.). The monthly charge for Schedules LS-1, LS-2 and OL-1 consists of a 24

non-energy facility portion and an energy portion based on the estimated usage 25

per lamp and an average energy rate. The average energy rate includes all 26

applicable components as set forth in Section A, above, and is derived in the 27

process of developing the revenue allocation. The average energy rate is the 28

same for Schedules LS-1, LS-2, LS-3 and OL-1, except that Schedule OL-1 29

pays the full PPP charge.2 30

2 Rates for Schedules LS-1, LS-2 and LS-3 do not include the California Alternate Rates

for Energy surcharge component of the PPP rate.

(PG&E-3)

6-3

In addition to the standard rates, this chapter includes PG&E’s proposals for 1

the LED Streetlight Conversion Program. The California Public Utilities 2

Commission (CPUC or Commission) approved this program to encourage 3

conversion of LS-1, OL-1, and CCSF lamps to LED lamps. Under the adopted 4

program, PG&E assesses an Incremental Facility Charge (IFC) in addition to the 5

facility rate for the standard lamp type (which originally was not an LED fixture). 6

C. Non-Energy Facility Charge Calculation for Schedules LS-1, LS-2, OL-1, 7

and CCSF Streetlights 8

In this proceeding, PG&E continues to base its non-energy facility charge 9

proposal on a simplified non-energy streetlight rate design model. This type of 10

simplified model was first introduced in PG&E’s 2003 GRC Phase II 11

(D.05-11-005) and has continued to be used in PG&E’s GRC Phase II 12

proceedings since that time. The method proposed herein was most recently 13

adopted in the settlement approved by the CPUC in D.18-08-013 (PG&E’s 14

2017 GRC Phase II decision), and is the basis for the currently effective 15

non-energy facility charges for these rate schedules. 16

Consistent with PG&E’s Revenue Allocation proposal in Chapter 2, PG&E 17

proposes to transition allocations to full cost of service over a period of 6 years. 18

Specifically, PG&E is proposing that streetlight facility charges be adjusted 1/6th 19

the way towards the full revenue requirement each year for the next three years. 20

PG&E would then reassess costs in its 2023 GRC Phase II and propose the 21

continuation of its transition plan in that proceeding. PG&E’s proposed facility 22

rates at full cost (that is, in year six of the transition) are provided in Table 6-2 at 23

the end of this chapter. 24

The three components of the non-energy facility charge, using the simplified 25

model, are: 26

Universal Charge; 27

Remaining operations and maintenance (O&M) Expense Charge; and 28

Plant-Related Charge. 29

Table 6-1, below, provides a summary of the applicability of these 30

non-energy facility charge components to each streetlight rate schedule: 31

(PG&E-3)

6-4

TABLE 6-1 APPLICABILITY OF NON-ENERGY FACILITY CHARGE COMPONENTS

Line No. Streetlight Rate Schedule

Universal Charge

O&M Charge

Plant-Related Charge

1 LS-1A through LS-1F Yes Yes Yes 2 LS-2A Yes No No 3 LS-2C Yes Yes No 4 OL-1 Yes Yes Yes 5 CCSF Yes Yes Yes

1. Universal Charge 1

The Universal Charge is imposed on all LS-1, LS-2, OL-1, and CCSF 2

streetlight customers regardless of whether the streetlight is owned by the 3

customer or by PG&E. The Universal Charge covers recovery of O&M, 4

Customer Accounts, and Administrative and General (A&G) expenses. 5

The O&M portion of the Universal Charge includes Distribution Maps 6

and Records, as well as Supervision costs. The Customer Accounts portion 7

of the Universal Charge includes the Streetlight Inventory Program. The 8

A&G portion of the Universal Charge is calculated by multiplying the test 9

year (TY) electric distribution A&G loader by the O&M expense. 10

a. O&M Expense 11

For its 2020 streetlight rates, PG&E uses 2018 actual Supervision 12

costs escalated to 2020 dollars. As it did in the prior GRC Phase II 13

proceedings beginning 2007, PG&E has continued to separate the O&M 14

streetlight expenses into the Universal Charge (Distribution Maps and 15

Records, and Supervision) and the Remaining O&M Expense Charge 16

(group replacements and burnouts). This separation enables PG&E to 17

unbundle the expense for group lamp replacements and burnouts. 18

b. Customer Accounts Expense 19

Similar to the 2017 GRC Phase II, in this 2020 GRC Phase II, PG&E 20

proposes to include the Streetlight Inventory Program cost in the 21

Universal Charge. This cost is specifically related to the lamp inventory 22

for Schedules LS-1, LS-2, OL-1 and CCSF, and is driven by record 23

keeping for each streetlight in the streetlight inventory. 24

(PG&E-3)

6-5

c. A&G Expenses 1

For this 2020 GRC Phase II, PG&E proposes to continue to 2

calculate the A&G expenses by multiplying the TY electric distribution 3

A&G loader by the O&M expenses in the Universal Charge.3 The 4

electric distribution A&G loader for this 2020 GRC Phase II, is equal to 5

31.63 percent, as described in Exhibit (PG&E-2), Chapter 10, “Marginal 6

Cost Loaders and Financial Factors.” 7

2. Remaining O&M Expense Charge 8

For its 2020 streetlight rates, PG&E uses 2020 test year estimates for 9

the streetlight O&M account shown in the Federal Energy Regulatory 10

Commission (FERC) Account 596 (Distribution Maintenance of Streetlighs 11

and Signal Systems.) 12

O&M expenses that were not incorporated into the Universal Charge, 13

such as group replacement and burnouts, appear in the Remaining O&M 14

Expense Charge. For this 2020 GRC Phase II, PG&E proposes to continue 15

to calculate the A&G expenses for this component by applying the TY 16

electric distribution A&G loader discussed in the previous paragraph. 17

3. Plant-Related Charge 18

The Plant-Related charge is developed first by determining the revenue 19

requirement for the capital cost of the streetlights and then separately 20

determining the replacement cost for each type of lamp in order to allocate 21

the revenue requirement among all lamp types in Schedules LS-1, OL-1, 22

and CCSF streetlights. 23

a. Plant Revenue Requirements 24

The Plant-Related charge is based on a revenue requirement that is 25

derived using the year-end balances of the streetlight plant accounts. 26

The revenue requirement is based on the cost of owning the streetlight 27

facilities for Schedules LS-1, OL-1, and CCSF and includes costs for 28

depreciation, uncollectibles, franchise fees, income taxes, property 29

taxes and return. In this proceeding, PG&E is proposing to collect the 30

revenue requirement in the plant-related charge, to reallocate that 31

3 A&G Loader is already embedded within the customer account expenses portion of the

Universal Charge.

(PG&E-3)

6-6

revenue to reflect updated replacement costs and to reflect a change to 1

the “most common lamp type” as discussed in more detail below. 2

b. Replacement Costs 3

The revenue requirement is allocated to each streetlight rate 4

schedule according to the replacement cost of each lamp type. There 5

are four basic lamp types currently in use on PG&E’s system: (1) High 6

Pressure Sodium Vapor (HPSV); (2) Mercury Vapor (MV); 7

(3) incandescent; and (4) newer technologies like LED street lamps. For 8

non-decorative CCSF and PG&E lamps, LED lamps are the most 9

common streetlight lamp type. PG&E expects that, by 2020, the most 10

common OL-1 non-decorative lamp type will be an LED lamp. 11

Accordingly, PG&E proposes to change rates to make LED the most 12

common lamp type in this proceeding for all non-decorative lamps as 13

described further below. 14

For this 2020 GRC Phase II, PG&E updates the streetlight 15

replacement cost on most lamp types with 2019 data, the most 16

up-to-date data available. PG&E continues to use the materials and 17

labor categories that were used to determine the rates in the Streetlight 18

rate Design Settlement adopted in D.18-08-013.4 Non-decorative 19

HPSV, MV and incandescent lamps are old, obsolete technologies that 20

are not supported by manufacturers and/or for which spare 21

parts/supplies are no longer available. Therefore, as these lamps fail or 22

burn out, the luminaire (and not just the lamp itself) is replaced by LED 23

luminaire with the equivalent number of lumens. As a result, PG&E 24

derived the replacement cost for these obsolete lamps based on the 25

replacement cost for LED lamps with the equivalent number of lumens.5 26

4 PG&E obtained the cost data for materials and labor (e.g., for each lamp type) to install

the replacement lamp from standard estimating tools that are routinely used in most construction projects.

5 Non-decorative HPSV, MV and incandescent lamps make up less than 21,000 of the approximately 196,000 PG&E-owned streetlights encompassed by the Plant-Related Charge.

(PG&E-3)

6-7

c. Plant Revenue Requirement Allocation 1

Once the total replacement costs are determined, the Plant 2

Revenue Requirement, or in this case the total current plant-related 3

facility charge revenue, is allocated to each lamp type in a three-step 4

process. First, PG&E calculates the Revenue Allocation Factors (RAF), 5

which is the ratio of the embedded revenue requirements compared to 6

the total replacement costs for all lamps under Schedules LS-1, 7

OL-1, and CCSF. Second, PG&E multiplies the RAF by the 8

replacement cost on each of the most common lamp type in Schedules 9

LS-1, OL-1, and CCSF to yield an annualized plant related charge rate. 10

Lastly, the annualized rates are then scaled to equal to the total required 11

revenue. 12

D. Energy Charge and Total Streetlight Rates for Schedules LS-1, LS-2 13

and OL-1 14

The total monthly charge per lamp for Schedules LS-1, LS-2, and OL-1 is 15

the sum of the non-energy facility charge and the product of the energy usage 16

per lamp and a volumetric (per kilowatt-hour (kWh)) rate which includes all other 17

costs allocated to these customers. Since Schedules LS-1, LS-2 and OL-1 are 18

not metered, energy usage for these rate schedules is derived based on the type 19

and size of lamp and lamp ballast, and the estimated number of hours during 20

which the lamp would operate each month. For this GRC Phase II, PG&E 21

proposes no change in the estimated hours of operation. Lamps are assumed 22

to be operated for approximately 11 hours per night on average, but not to 23

exceed 4,100 hours per year for all-night rates. 24

The volumetric energy rate is determined by subtracting non-energy facility 25

charge revenues from Schedules LS-1, LS-2, and OL-1 lamps, as well as the 26

applicable Schedule LS-3 basic service fee from the total revenue allocated to 27

the streetlight class, and then dividing the difference by the applicable sales, in 28

kWh. The energy rate is the same for Schedules LS-1, LS-2, LS-3 and OL-1, 29

except that Schedule OL-1 pays the full PPP charge. 30

E. Rate Design for Schedule LS-3 31

As noted in the Background section of this testimony, Schedule LS-3 32

includes a customer charge and an energy rate that does not vary by season or 33

(PG&E-3)

6-8

by time of use. PG&E is not proposing to change the LS-3 customer charge in 1

this proceeding. 2

F. City and County of San Francisco Streetlight Rates 3

PG&E provides O&M services to the streetlights that are located in 4

San Francisco. These CCSF streetlights obtain their energy from the city’s 5

Hetch Hetchy Project and not from PG&E. In this proceeding, PG&E proposes 6

to set rates for CCSF’s streetlights using the same approach adopted in the 7

settlement approved by the CPUC in D.18-08-013 (PG&E’s 2017 GRC Phase II 8

decision), subject to the adjusting the facility charge 1/6th of the way towards 9

the full revenue requirement each year for the next three years as proposed for 10

non-CCSF lamps. PG&E’s proposed non-energy facility charges at full cost 11

(that is, in year six of the transition) for the CCSF rate schedules are shown in 12

Table 6-2 at the end of this chapter. 13

G. LED Streetlight Conversion Program 14

1. Non-Decorative Lamps 15

The IFC was eliminated for non-decorative LS-1 lamps in the in the last 16

GRC and replaced with a rate for a standard LED lamp. In this proceeding, 17

PG&E proposes to eliminate the LED Streetlight Conversion Program for 18

non-decorative streetlights where more than half of the lamps have already 19

been converted to LED, or where PG&E expects more than half of the lamps 20

will be converted to LED by 2020. Specifically, PG&E proposes to eliminate 21

the IFC on Schedules OL-1 and CCSF non-decorative lamps, and replace 22

the rate with an LED streetlight facility charge rate. The revision will 23

eliminate the need for the IFC adder on these schedules. That is, rather 24

than calculating an LED conversion adder, PG&E will calculate the facilities 25

cost for OL-1 and CCSF using an LED replacement cost. 26

(PG&E-3)

6-9

2. Decorative Lamps 1

Pursuant to Public Utilities Code Section 384.5,6 PG&E filed and the 2

Commission approved the LED Streetlight Conversion Program for 3

decorative lamps in Advice 4661-E (PG&E-owned decorative lamps) and in 4

Advice Letter 4662-E (CCSF decorative lamps). Like the similar program for 5

non-decorative lamps, customers are required to pay an IFC in addition to 6

their otherwise applicable streetlight rate. The approved IFC of $12.768 per 7

month for decorative CCSF lamps and for decorative lamps served under 8

Schedule LS-1D has been in effect since 2016. PG&E’s experience with the 9

program to date has been that only 13.5 percent of PG&E lamps that would 10

be eligible for the program have been converted and only 13.5 percent of 11

CCSF lamps have been converted. In this proceeding, PG&E has reviewed 12

the calculations for the decorative IFC based on more recent data and 13

proposes to reduce the adder from its current level to $6.226.7 As is the 14

case with the current decorative IFC, the proposed IFC would be applied in 15

the addition to the facility rate for the standard lamp type (which originally 16

was not an LED fixture). PG&E is hopeful that the revised IFC for 17

decorative streetlights will encourage greater customer adoption of LED 18

lighting during this GRC cycle. 19

H. Network-Controlled Dimmable Streetlight 20

1. Pilot Program 21

A Pilot Program for Network-Controlled Dimmable Streetlights (Pilot) 22

was established as part of the Streetlight Settlement Agreement approved 23

6 384.5. (a) On or before March 1, 2014 the commission shall order electrical

corporations to submit, on or before July 1, 2015, a tariff to be used, at the discretion of local governments, to fund energy efficiency improvements in street light poles owned by the electrical corporations to ensue reduced energy consumption for local governments who are streetlight customers covered by these tariffs. (b) The tariff shall be designed to allow local governments to remit the cost of the improvement through the tariff over time, resulting in reduced energy consumption, without shifting costs to nonparticipating ratepayers. The cost of the improvement shall be identified separately rather than included within the charge for electrical service.

7 CCSF’s historical Golden Triangle and Dragon lights are not eligible for the decorative LED conversion program due to the highly specialized nature of these lights.

(PG&E-3)

6-10

by the CPUC in PG&E’s 2011 GRC Phase II (D.11-12-053).8 The Pilot was 1

revised in the Streetlight Settlement Agreement approved by the CPUC in 2

PG&E’s 2014 GRC Phase II (D.15-08-005).9 As compared with the 2011 3

Dimmable Pilot Program, which is now closed to new enrollment, the 2014 4

Dimmable Pilot Program was expected to provide dimmable streetlight 5

service as an option to Schedule LS-2 that was simpler and offered 6

participants some certainty that they would benefit from related energy 7

savings in a timely and mutually-workable way. To date, there is only 8

one participant in the 2011 pilot and there are no participants on the 2014 9

pilot program. 10

In Phase II of the 2017 GRC proceeding, the Commission adopted the 11

Streetlight Rate Design Settlement as part of D.18-08-013. Among other 12

things, the Settlement Agreement required that PG&E hold a workshop to 13

discuss the feasibility of a fully-automated, dimmable streetlight and ancillary 14

device billing system. In addition, the settlement required that PG&E 15

develop a report including a work plan and cost estimate for such a system 16

and include the report in Phase I of the 2020. Accordingly, the Compliance 17

Report was filed in Phase I of the 2020 GRC proceeding.10 As part of the 18

Compliance Report, PG&E stated that it: 19

…does not recommend the Commission pursue a fully integrated 20 metering and billing option for dimmable streetlights at this time in light 21 of the relative costs to both customer and to PG&E.11 22

In that same proceeding, California City-County Street Light Association 23

recommended that the Commission approve a fully-integrated billing and 24

metering solution for dimmable streetlights that utilized customer-owned 25

meters.12 26

8 See D.11-12-053, mimeo, pp. 55-58, adopting, without modification, the uncontested

Amended Streetlight Settlement Agreement attached to that decision as Appendix D, Attachment 3. See also Resolution E-4421 approving the necessary Special Contract that would allowing participants’ billing to deviate from PG&E’s existing LS-2 streetlight rate schedule, to allow for reductions due to dimmable LED streetlights under this pilot.

9 See the Streetlight Rate Design Settlement, p. 5. 10 Application (A.) 16-12-009, Exhibit (PG&E-7), WP 8-163 to WP 8-188. 11 A.16-12-009, Exhibit (PG&E-7), WP 8-169 to WP 8-170; Exhibit (PG&E-28), p. 9-4. 12 A.16-12-009, CALSLA-01, p. 1, lines 21-24; p. 9, line 27 to p. 10, line 9.

(PG&E-3)

6-11

In Rebuttal Testimony, PG&E expanded on why the Commission should 1

not approve a fully-automated billing and metering at this time. First, 2

whether the meters would be customer-owned or owned by PG&E, the 3

Information Technology costs of the programs would be considerable and 4

the potential costs that would be incurred by customers to achieve the 5

desired benefit are uncertain. While the pilot program has demonstrated 6

that for a subset of pilot locations, the concept of utilizing measured usage 7

to calculate an energy credit for dimming was valid, the pilot has not 8

provided an adequate demonstration that customer-owned meters and data 9

delivery systems are capable of providing the information to PG&E that is 10

necessary billing in a timely and complete manner.13 Instead, PG&E 11

proposed to continue the pilot program for customers that had installed 12

dimming equipment, and consider revisions to make the program more in 13

line with customer needs. Continuation of the pilot program would provide, 14

at a minimum, benefits of a basic dimming schedule while providing an 15

opportunity to participating customers to improve the capability of their 16

systems. PG&E plans to initiate a discussion with interested parties to 17

determine whether the pilot program should be revised or enhanced.14 18

2. Rate Design for a Fully-Integrated Metered and Billing Solution for 19

Dimmable Streetlights 20

In anticipation that a fully-integrated metering and billing solution could 21

be approved in Phase I of the 2020 GRC, D.18-08-013 also requires that 22

PG&E provide a rate design in this Phase II proceeding for dimmable 23

streetlights that could be employed with such a system if approved in 24

Phase I. As of the date this testimony was filed, a decision Phase I of the 25

2020 GRC has not been issued. Accordingly, in compliance with 26

D.18-08-013, PG&E has included its required rate design proposal as 27

Appendix I of Exhibit (PG&E-4). 28

13 A.16-12-009, Exhibit (PG&E-28), pp. 9-6 and 9-7. 14 On December 20, 2019, PG&E filed a motion seeking approval of the Settlement

Agreement in Phase I of the 2020 GRC (A.18-12-009). Beginning on page 41 (Section 5.6.2), the Settlement Agreement identifies several actions that will be taken to improve the current pilot program within 60 days of the date the Settlement Agreement is approved.

(PG&E-3)

6-12

I. Conclusion 1

PG&E requests that the Commission adopt its proposed rate design for 2

non-energy facility charges for Schedules LS-1, LS-2, OL-1, and CCSF 3

streetlights, and its proposed energy charges for all streetlight rate schedules. 4

PG&E also requests revisions to the LED Streetlight Conversion Program as 5

noted above and continuance of a Dimmable Streetlight Pilot Program subject to 6

input from the parties in this proceeding.7

6-13

TAB

LE 6

-2FA

CIL

ITY

CH

AR

GES

FO

RST

REE

TLIG

HT

RA

TES

(PG&E-3)

(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 7

THE ECONOMIC DEVELOPMENT RATE

(PG&E-3)

7-i

PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 7

THE ECONOMIC DEVELOPMENT RATE

TABLE OF CONTENTS

A. Introduction ............................................................................................................ 7-1

B. Overview of the EDR Program ............................................................................. 7-1

1. History of the EDR Program .......................................................................... 7-1

a. Parameters of the 2018-2020 EDR Program ......................................... 7-2

b. Parameters of the 2014-2017 EDR Program ......................................... 7-4

C. Success of the EDR Program Since D.13-10-019 .............................................. 7-4

D. Revenue Evaluation .............................................................................................. 7-6

1. CTM Program Results: 2014-2017 Program ............................................... 7-7

2. CTM Program Results: 2018-2020 Program ............................................... 7-9

E. Economic Conditions and Keeping California Competitive................................. 7-9

1. California’s Economic Conditions .................................................................. 7-9

2. The State of Competition at National Utilities ............................................. 7-15

F. Proposal for the 2021-2023 Program ................................................................. 7-16

1. Program Characteristics............................................................................... 7-16

2. CTM Analysis................................................................................................ 7-17

G. Compliance With EDR D.18-08-013 Requirements .......................................... 7-19

H. Conclusion ........................................................................................................... 7-20

(PG&E-3)

7-1

PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 7 2

THE ECONOMIC DEVELOPMENT RATE 3

A. Introduction 4

This chapter presents Pacific Gas and Electric Company’s (PG&E) proposal 5

for its Economic Development Rate (EDR) in the 2020 General Rate Case 6

(GRC) Phase II. Public Utilities Code Section 740.4(a) provides that the 7

California Public Utilities Commission (CPUC or Commission) shall authorize 8

public utilities to engage in programs to encourage economic development. 9

PG&E proposes to continue offering its EDR to attract jobs and companies to 10

locate in California when they have out-of-state choices and to retain companies 11

considering leaving California. PG&E proposes to continue its EDR until 12

December 31, 2023 (or until a decision is rendered in Phase II of the 2023 GRC, 13

whichever is later), reduce the maximum rate reduction percentage from 14

25 percent to 20 percent, and to establish an increase of 150 megawatts (MW) 15

for large businesses and 5 MW for small businesses to the current program cap 16

of 145 MW. PG&E also proposes to revise the proportions used to allocate the 17

rate reduction to distribution and generation components of the bill. 18

B. Overview of the EDR Program 19

1. History of the EDR Program 20

On November 13, 2012, PG&E filed Application 12-03-001, Application 21

for Approval of Economic Development Rate for 2013-2017 to extend and 22

revise its EDRs. On October 3, 2013, the Commission issued Decision 23

(D.) 13-10-019 which authorized PG&E to offer an EDR tariff with a 200 MW 24

cap and a maximum rate reduction of 30 percent to help compete for 25

out-of-state business. The EDR Program offered the discounted electric 26

rate over a 5-year period to help with attraction, expansion, and retention 27

activities. On August 9, 2018, in the decision on PG&E’s Proposed Rate 28

Designs and Related Issues, the CPUC adopted an all-party settlement, a 29

renewed program with some changes agreed to by the settling parties, as 30

described below. 31

(PG&E-3)

7-2

a. Parameters of the 2018-2020 EDR Program 1

This section outlines the parameters and qualification process of 2

the current 2018-2020 EDR Program for each customer applying for 3

the EDR. 4

Qualification Criteria 5

To qualify, a company must: 6

– Have out-of-state options for a new facility or an expansion 7

facility or have a current operation in California that is at risk of 8

ceasing operations; 9

– Supply documentation to show out-of-state choices or other 10

operational scenarios; 11

– Sign an affidavit attesting to the fact that but for this incentive 12

rate, either on its own or in combination with a package of 13

offerings, the customer would not have retained or expanded its 14

load within California or would not have located in California; 15

– Pass an eligibility review with the California Governor’s Office of 16

Business and Economic Development; 17

– Be a relocatable type of business, e.g., a retail store is not a 18

relocatable business because it is locally tied to its consumer 19

base; and 20

– Submit an annual report that includes the number of jobs, types 21

of jobs, and average wages and benefits for the jobs created or 22

retained. 23

Rate Reduction Tiers 24

The EDR has three rate reduction tiers which are dependent on 25

the annual average of local unemployment rate at the city or 26

county level, in comparison to the annual average unemployment 27

across California. The current rate reduction tiers respectively 28

provide 12 percent, 18 percent, or 25 percent off the monthly 29

electricity bill, with the greater discounts going to projects in cities 30

and counties with higher unemployment rates. Specifically, PG&E’s 31

mid-enhanced tier (Tier 2) makes available an 18 percent rate 32

reduction for those cities and counties that have an annual 33

unemployment rate between 130 and 150 percent of California’s 34

(PG&E-3)

7-3

average. Tier 3, the 25 percent rate reduction, is only available in 1

those cities and counties that have an annual unemployment rate 2

above 150 percent of California’s average. For all other areas of 3

PG&E’s service territory, qualifying customers are eligible for the 4

standard 12 percent rate reduction under Tier 1. 5

PG&E is proposing to retain three rate reduction tiers and the 6

current associated unemployment thresholds. The standard (Tier 1) 7

and mid-enhanced (Tier 2) will remain in place with rate reductions 8

of 12 percent and 18 percent, respectively, and the enhanced tier 9

(Tier 3) rate reduction will be lowered from 25 percent to 20 percent 10

in consideration of the Contribution to Margin (CTM) Analysis 11

presented in Section F.2. below. 12

Program Cap and Allocation 13

The current program (2018-2020) has cap space of about 14

80 MW that has been rolled over from the 2014-2017 program. This 15

unused cap space will be allocated as follows: 16

TABLE 7-1 UNUSED CAP SPACE

Line No. Tier

Allocation of Remaining CAP

1 1 – Standard EDR (12% rate reduction) 20% 2 2 – Mid-enhanced EDR (18% rate reduction) 20% 3 3 – Enhanced EDR (25% rate reduction) 20% 4 4 – Unrestricted (Tiers 1-3) 40%

An additional 60 MW of additional cap space was allowed within 17

the 2018-2020 EDR Program, allocated as indicated below: 18

TABLE 7-2 ADDITIONAL CAP SPACE

Line No. Tier Allocated Load

1 1 – Standard EDR (12% rate reduction) 20 MW 2 2 – Mid-Enhanced EDR (18% rate reduction) 20 MW 3 3 – Enhanced EDR (25% rate reduction) 20 MW

(PG&E-3)

7-4

This leaves a total of about 140 MW available in the 2018-2020 1

program for projects with an electricity load of at least 150 kilowatts 2

(kW) of demand. Another new feature agreed upon in the 3

settlement is an additional small business cap of 5 MW provided for 4

projects with demand below 150 kW. 5

As projects are signed onto the EDR, the projected load is 6

allocated to the applicable restricted tier. Once the cap from a tier 7

has been used up, the EDR participant’s load can be allocated to 8

either the unrestricted tier or to a lower tier which provides a lower 9

rate reduction percentage at PG&E’s discretion. 10

b. Parameters of the 2014-2017 EDR Program 11

The 2014-2017 program was similar to the 2018-2020 program, with 12

the main differences being: 13

There used to be two tiers instead of three tiers, at 12 percent and 14

30 percent; 15

The 200 MW cap did not have different allocations based on the 16

percentage tier and no separate small business cap; 17

The minimum threshold was 200 kW instead of 150 kW, with no 18

exemptions for small businesses; and 19

Renewals were allowed in certain cases. 20

C. Success of the EDR Program Since D.13-10-019 21

Since the inception of the EDR Program and PG&E’s active efforts to attract 22

and retain qualified businesses in California, from 2014 to JulyDecember 2019, 23

the program has achieved the results below. The jobs and wage numbers are 24

listed in the annual compliance reports that have been reported to the CPUC. 25

(PG&E-3)

7-5

TABLE 7-3 EDR PROGRAM RESULTS

Line No. Metric

2014-2017 EDR Program(a)

2018-2020 EDR Program(a)

1 Projects signed 57 1317 2 Total energy load

per tier 12%: 54.6 MW 30%: 85.5 MW Total: 140.1 MW

12%: 7.2.68 MW 18%: 0.027 MW 25%: 16.426.6 MW Total: 23.629.26 MW

3 Projected jobs created 10,187 4,046416 5 Actual Jobs created 8,843 N/A 6 Actual Wages created $76,899,978.30 N/A 7 CTM $18.4 Million N/A 8 Projects signed

by region Bay Area: 14 Central Coast: 5 Greater Sacramento: 4 Northern California: 2 Northern Sacramento Valley: 4 San Joaquin Valley: 28

Bay Area: 3 Central Coast: 4 Central Sierra: 1 North Sacramento Valley: 1 San Joaquin Valley: 48

9 Unused cap (MW) 80.6 MW (rolled over) 116.4123.18 MW (as of JulyDecember 2019)

_______________ (a) The 2018-2020 EDR Program launched in October 2018. The 2014-2017 program

ran f rom 2014 through September 2018, and the 2018-2020 program is running from October 2018 through present. Data in table is updated as of JulyDecember 2019.

Since 2014, the EDR Program has provided such benefits as: 1

Over $8899.6 million of new annual recurring revenue to PG&E to help 2

lower the bills of all customers, because this is incremental electric revenue 3

that would have gone out-of-state or not come to California; 4

Over $1821 million of CTM after full non-bypassable charges (NBC) are 5

applied; and 6

Support for small businesses: 7

– Since adding the small business cap into the 2018-2020 program, 8

PG&E has been able to support struggling small businesses in our 9

service area. One recent example is a small manufacturer of electronics 10

in Santa Maria, CA with 20 kW of electric load, whose owner was 11

considering moving the business (which included ten jobs) to Texas due 12

to recent high import tariffs and the anticipation of a higher minimum 13

wage in California. PG&E was able to approve the EDR at a 25 percent 14

rate reduction, which helped lower costs for them to continue operating 15

in Santa Maria. 16

(PG&E-3)

7-6

The EDR is a powerful tool, along with other local and statewide incentives, 1

to keep California on the consideration list for siting new businesses or for the 2

expansion of facilities by existing businesses. For example, Zodiac Aerospace 3

(with permission from the company to disclose that they are on the EDR), is a 4

French-owned company with manufacturing facilities in Europe and in Mexico. 5

Their Santa Maria, California location employs 1,200 workers and makes seat 6

shells for airliners. When the parent company initially made a decision to 7

eliminate this facility and shift its remaining California operations to Mexico, 8

PG&E and the Governor’s Office of Business and Economic Development 9

worked to expedite a package of incentives, including the EDR along with other 10

incentives, that persuaded Zodiac Aerospace to change that decision and keep 11

its operations in Santa Maria, California instead. 12

The EDR has also been successful at tipping the decision to site regional 13

facilities, such as large telecom data centers or logistics fulfillment centers in 14

California, when they could have sited in Arizona or Nevada. For reference, the 15

price of electricity in Arizona is $0.11 per kilowatt-hour (kWh) and $0.07 in 16

Nevada on average, compared to California’s average of $0.15. 17

When selecting sites, companies engage in a methodical search and 18

eliminate sites in various rounds based on their business needs. When the cost 19

of utilities is a top ten factor on the list, the EDR Program is an important tool for 20

keeping California within the consideration set. 21

D. Revenue Evaluation 22

The EDR allows PG&E to attract and retain customers, resulting in revenue 23

that otherwise would not have located or remained in California. This results in 24

sales that are higher than they would be, absent these customers. When PG&E 25

can retain or attract sales at a rate that is lower than the tariffed rate, but higher 26

than the marginal cost of service, it helps to maintain or add to CTM. This CTM 27

can be used to keep rates to non-participating customers lower than they 28

otherwise would be by allowing PG&E to spread its costs over more units of 29

sales, thus benefiting all ratepayers. 30

In the 2018-2020 EDR Program, the CTM is determined on a total portfolio 31

basis and reported under existing confidentiality rules. This applies for retention, 32

attraction, and expansion projects. However, for retention EDR customers, a 33

before-the-fact CTM calculation is done before approving the rate, in order to 34

(PG&E-3)

7-7

confirm that retention customers with negative CTM are not enrolled in the 1

program. PG&E proposes to continue this rule in the 2021-2023 program. 2

1. CTM Program Results: 2014-2017 Program 3

PG&E compared the revenue from EDR participants to the marginal 4

cost consisting only of marginal economic costs applicable to customers 5

receiving the EDR over a short term: Marginal Generation Energy costs 6

(Marginal Generation Capacity costs are excluded pursuant to 7

D.13-10-019); Transmission Charges; Marginal Customer Access Costs; 8

Marginal Distribution Capacity Costs to the extent the customer is located 9

within a constrained Distribution Planning Area; and NBCs.1 All marginal 10

cost values were used as adopted for contract evaluation purposes in the 11

Marginal Cost and Revenue Allocation Settlement adopted by D.15-08-005 12

in PG&E’s 2014 GRC Phase II. Under this analysis, the participants 13

contributed positive CTM in the amount of $18.4 million for the EDR 14

Program from 2014 through 2017. 15

The EDR Program, from 2014 to 2017, has had a large, positive CTM 16

even though there has been a handful individual projects whose CTM, on 17

average, was somewhat negative, but those have been limited. Specifically, 18

out of 52 total EDR projects, six of them had a negative CTM. Of these, 19

most of the negative CTM was due to $1.107 million from one large 20

customer. The majority of negative CTM projects come from customers 21

either on a transmission rate, or those that are on Direct Access (DA) or 22

Community Choice Aggregation (CCA) Service. Overall the portfolio has 23

been overwhelmingly positive at $18.421.3 million (see table below—data 24

updated through JulyDecember 2019), so ratepayers have benefitted 25

significantly from this program. 26

1 NBCs include: Public Purpose Program charges, the Department of Water Resources

Bond charges, Nuclear Decommissioning, Competition Transition Charges, the New System Generation Charge, the Energy Cost Recovery Amount and the Power Charge Indifference Adjustment (PCIA), as applicable for customers electing DA and CCA service.

(PG&E-3)

7-8

TABLE 7-4 CTM, 2014-2017 EDR PROGRAM RESULTS

Project Contract Start Date

EDR Margin – Withwith Full NBCs

1 7/29/2014 $1,439,810.171,546,248.03 2 8/3/2014 1,187,946.381,351,246.50 3 9/2/2014 866,057.62973,984.96 4 9/29/2014 538,961.43590,373.94 5 9/30/2014 (1,124,020.08(1,071,590.89) 6 10/12/2014 255,236.00280,497.67 7 10/12/2014 1,568,720.461,838,230.20 8 1/4/2015 1,120,149.201,193,219.63 9 1/31/2015 (321,721.77(343,645.74) 10 3/19/2015 347,160.97373,075.25 11 3/26/2015 127,196.85138,910.46 12 6/4/2015 416,379.67494,187.70 13 6/22/2015 (83,289.42(59,965.89) 14 6/28/2015 428,823.05478,129.67 15 9/16/2015 6,999,818.157,761,877.98 16 11/30/2015 93,321.28107,216.87 17 12/8/2015 142,958.65158,654.45 18 1/1/2016 (115,356.41(37,294.38) 19 1/10/2016 139,361.05157,591.82 20 2/8/2016 60,408.50 21 3/13/2016 145,939.27176,972.62 22 3/13/2016 30,980.7536,092.31 23 4/6/2016 177,357.39201,694.92 24 5/12/2016 10,277.83 25 5/12/2016 373,547.98413,652.09 26 5/12/2016 248,278.74275,854.55 27 5/12/2016 216,738.81236,317.17 28 5/15/2016 31,139.22 29 5/31/2016 77,306.9399,215.00 30 6/13/2016 8,354.419,218.07 31 12/4/2016 37,444.0946,694.91 32 12/8/2016 253,072.48 33 12/22/2016 61,681.7382,662.30 34 12/29/2016 262,776.07392,644.79 35 12/29/2016 175,736.98271,906.60 36 4/30/2017 (331,583.77(353,293.44) 37 5/4/2017 117,099.72140,570.94 38 5/11/2017 12,087.1914,731.01 39 5/23/2017 97,644.12107,353.46 40 5/25/2017 70,287.4170,995.95 41 5/25/2017 217,728.74255,232.22 42 6/11/2017 1,160,297.811,393,173.80 43 10/31/2017 351,373.74462,546.77 44 12/12/2017 63,732.2281,945.10 45 12/28/2017 125,390.29157,401.41 46 1/5/2018 336,809.71415,023.74 47 2/5/2018 10,040.92 48 3/4/2018 8,385.4847,505.59 49 3/4/2018 46,251.80135,191.56 50 7/16/2018 2,090.39 51 8/31/2018 (95,495.85(132,004.39) 52 9/18/2018 1,844.163,195.36 53 Total $18,392,538.5321,340,471.93

(PG&E-3)

7-9

2. CTM Program Results: 2018-2020 Program 1

The 2018-2020 program started enrolling participants in October 2018. 2

At the time of this submission, most of the contracts since October 2018 had 3

less than a year of billing data on the EDR. Therefore, it was not possible to 4

get complete CTM calculations, since partial year’s contribution would not 5

be representative of a full year including all seasonality, etc. In calculating 6

CTM, one would expect to see a similarly positive contribution across the 7

portfolio, taking into account that PG&E is not signing retention projects with 8

a projected negative CTM. PG&E will be able to run an additional CTM 9

calculation in January 2020, which would provide analysis for projects that 10

have completed a year of billing data at the end of 2019. 11

E. Economic Conditions and Keeping California Competitive 12

1. California’s Economic Conditions 13

Since D.18-08-013, the economy in California has so far continued to 14

improve with solid Gross Domestic Product growth and declining 15

unemployment rates. Still, the economic recovery has not been equal 16

across the state. While certain counties in the Bay Area, for example, had 17

less than 2.6 percent average annual unemployment rates in 2018,2 parts 18

of PG&E’s territory such as Fresno County still had high unemployment 19

over twice as high at 7.5 percent.3 Nearly 70 percent of job growth from 20

2010-2018 came from coastal areas, whereas the inland areas such as 21

San Joaquin Valley have faced, and continue to see, higher structural 22

unemployment and created fewer jobs in the state’s fastest 23

growing industries.4 24

Although it is clear that California’s inland areas are places of great 25

potential, they have not had the same job growth or investment activity as 26

the state’s coastal areas. As a result, there have recently been multiple 27

initiatives across California that have focused on lifting inland regions to 28

match the prosperity seen in other parts of the state. In 2019, California’s 29

2 https://www.labormarketinfo.edd.ca.gov/file/lfhist/18aacou.pdf. 3 Id. 4 https://www.pe.com/2019/05/10/regions-rise-together-building-a-plan-for-inclusive-

sustainable-growth-across-california/.

(PG&E-3)

7-10

Governor’s Office of Business and Economic Development launched a new 1

initiative, Regions Rising Together, to build a comprehensive plan seeking 2

to bring more of California’s fast-growing prosperity into inland regions 3

through investment, policy, and sustainable development. Other inland 4

initiatives have also been launched, such as Inland California Rising,5 a 5

broad coalition of leaders and organizations in the business, philanthropic, 6

non-profit, and public sectors which have formed to improve progress for the 7

inland counties. 8

PG&E’s EDR aligns very well with these recent initiatives, since the 9

EDR is structured to only provide a higher rate reduction to those counties 10

with higher unemployment rates, which are largely located in inland areas. 11

Out of the 31 counties in California that had above-statewide average 12

unemployment rates in 2018, 27 of them are in PG&E’s service area. Of 13

those 27 counties, 18 are eligible for either the Mid-Enhanced (18 percent) 14

or Enhanced (25 percent) rate reduction. California-wide, PG&E’s service 15

area includes almost all the counties with unemployment rates higher than 16

the statewide average, which was 4.2 percent as of December 2018. (See 17

Table 7-5 and Figure 7-1). 18

5 http://inlandrising.org/.

(PG&E-3)

7-11

TABLE 7-5 2018 CALIFORNIA STATEWIDE UNEMPLOYMENT RATES BY COUNTY

Ranking County Unemployment

Rate % Tier Utility

1 Imperial County 18.1% 25% Other 2 Colusa County 12.9% 25% PGE 3 Tulare County 9.6% 25% PGE 4 Merced County 8.3% 25% PGE 5 Kern County 8.0% 25% PGE 6 Kings County 7.7% 25% PGE 7 Fresno County 7.5% 25% PGE 8 Modoc County 7.5% 25% Other 9 Plumas County 7.5% 25% PGE 10 Sutter County 7.5% 25% PGE 11 Madera County 7.0% 25% PGE 12 Siskiyou County 6.7% 25% PGE 13 Glenn County 6.5% 25% PGE 14 Stanislaus County 6.4% 25% PGE 15 Yuba County 6.4% 25% PGE 16 Monterey County 6.3% 25% PGE 17 San Joaquin County 6.0% 18% PGE 18 Sierra County 5.9% 18% PGE 19 Tehama County 5.7% 18% PGE 20 Trinity County 5.7% 18% PGE 21 Del Norte County 5.5% 18% Other 22 Mariposa County 5.3% 12% PGE 23 Lake County 5.2% 12% PGE 24 San Benito County 5.1% 12% PGE 25 Butte County 4.9% 12% PGE 26 Shasta County 4.9% 12% PGE 27 Santa Cruz County 4.9% 12% PGE 28 Lassen County 4.8% 12% PGE 29 Los Angeles County 4.7% 12% Other 30 Alpine County 4.6% 12% PGE 31 Tuolumne County 4.6% 12% PGE

________________ Note: California Average (2018), 4.2 percent.(State of California Employment

Development Department)

(PG&E-3)

7-12

FIGURE 7-1 2018 CALIFORNIA STATEWIDE UNEMPLOYMENT RATES BY COUNTY

(FROM STATE OF CALIFORNIA EMPLOYMENT DEVELOPMENT DEPARTMENT)

The EDR has been very successful in supporting Governor Newsom’s 1

Office of Business and Economic Development’s goal of bringing or 2

retaining jobs and business investment into the inland regions. Out of 3

70 projects signed through the EDR Program through July 2019, 43 have 4

been in inland counties, creating or retaining 5,7106,360 jobs. The map 5

below, which shows where EDR jobs and projects have been located, 6

makes it clear that a significant number of jobs have been brought to inland 7

counties with support from the EDR Program. 8

(PG&E-3)

7-13

FIGURE 7-2 EDR PROGRAM MAP AS OF JULY 2019 – NUMBER OF PROJECTS AND JOBS CREATED

(FROM PG&E EDR 2014-2017 AND 2018-2020 PROJECT DATA)

(PG&E-3)

7-14

The EDR incentive is a critical part of the state of California’s strategy to 1

support the economic vitality of the inland region. These areas rely on 2

incentives such as the EDR to be able to compete with other states and 3

other countries. Removing or reducing the ability to provide an appropriate 4

rate reduction on electricity would make any overall incentive package less 5

competitive, and would harm the efforts spearheaded by the Governor’s 6

Office of Business and Economic Development. Therefore, PG&E proposes 7

(PG&E-3)

7-15

to continue the EDR Program with the lower Enhanced rate reduction tier 1

under its previously-approved terms. 2

2. The State of Competition at National Utilities 3

Most larger utilities in the United States (U.S.) have a robust economic 4

development program, because it strengthens the communities that they 5

serve, but also, it is an effort with either high return-on-investment where a 6

utility’s profits depend on load, or CTM helping cover rates for all customers 7

in states like California cost-of-service decoupled ratemaking. Other 8

large utilities in the U.S. have economic development groups with 9

26-40 employees, marketing a variety of incentives, rebates, and other 10

programs. By comparison, PG&E’s Economic Development Program has 11

achieved its results with only five employees. 12

The state of competition for California’s customers has become more 13

intense since 2014, with print advertisements by other utilities featured in 14

airplane magazines serving California routes, to radio ads targeting 15

high-energy use commercial and industrial customers. Another large 16

out-of-state investor-owned utility has hired permanent staff in 17

San Francisco for the purpose of attracting PG&E commercial and 18

industrial customers to relocate to their territory in the Midwest and 19

East Coast, where the per kWh price of electricity is almost half of 20

California’s, even though overall bill in California might be lower due to the 21

state’s moderate climate and focus on energy efficiency. 22

While the continuing EDR Program will not match other states on a cost 23

basis, it will however, continue to help achieve the purpose of not eliminating 24

California as a part of the site selection process when there are out-of-state 25

options. It remains clear that PG&E’s EDR is part of a comprehensive 26

package of incentives and initiatives that encourages investment into 27

California, with an emphasis on areas that need it most, such as the inland 28

cities and counties. 29

The current EDR Program, which resulted from an all-party settlement, 30

has been carefully designed to work both during economic recession cycles 31

and in expansionary cycles, either of which can happen within a 3-year 32

regulatory cycle. During a recession, the EDR helps retain companies in 33

California that are seeking to move to lower-cost areas of the U.S. On the 34

(PG&E-3)

7-16

other hand, during times of economic expansion, it helps level the playing 1

field with neighboring states when attracting new facilities or expansions to 2

site in California. As economic activity increases across the U.S., California 3

must continue to find ways to be more competitive in order to attract the 4

growth that will be needed when the inevitable economic recession occurs, 5

especially in the inland areas of the state. 6

F. Proposal for the 2021-2023 Program 7

1. Program Characteristics 8

As described above, the all-party EDR settlement approved In 9

D.18-08-013 moved the program to a three-tiered system, as well as 10

introduced some new terms and conditions. 11

In practice, PG&E believes that many of the new features of the 12

program to be of great benefit, such as the prohibition against renewals of 13

the EDR at the same facility and the mandated energy reduction 14

requirement. Therefore, for the 2021-2023 EDR, PG&E proposes to keep 15

all parameters of the 2018-2020 program, including the three-tier system of 16

discounts based on unemployment level, along with the following changes 17

or additions: 18

The Enhanced tier (Tier 3) rate reduction percentage will be lowered 19

from 25 percent to 20 percent; 20

A 150 MW cap increase that can be used towards all three rate 21

reduction tiers (unrestricted) for businesses with 150 kW of demand or 22

more; 23

A 5 MW cap for small businesses with under 150 kW of demand; and 24

Any unused load space from the 2018-2020 program will be rolled over 25

into the new program and applied using the same tiered bucket rules 26

from the 2018-2020 program. 27

Since the start of PG&E’s EDR Program, between 20 and 44 MW per 28

year have signed onto the program (see below). 29

(PG&E-3)

7-17

TABLE 7-6 PG&E EDR PROGRAM – MW SIGNED PER YEAR

Line No. Year

MW Signed Into the EDR Program

(2014 – July 2019)

1 2014 20.3 2 2015 19.1 3 2016 20.1 4 2017 43.7 5 2018 41.9 6 2019

(YTD as of July) 2324.2

As of April 1, 2020, 13.64 MW of load under the current program cap of 1

145 MW has been retired. Assuming an optimistic scenario, under which 2

50 MW per year would enter the program in the future, PG&E anticipates 3

using almost 100 MW of total cap through 2020 from the 2018-2020 4

program. This would leave almost zero load space to be rolled-over after 5

the 2020 program ends. This would still leave a need for roughly 150 MW of 6

additional capacity for the 2021-2023 program. Therefore, PG&E is 7

requesting an increase of 150 MW for large businesses and 5 MW for small 8

businesses with electricity load under 150 kW, beyond the current program’s 9

cap of 145 MW. This will ensure that the program continues to have 10

adequate capacity to support the state’s important economic policy 11

initiatives, while providing benefits to ratepayers. 12

2. CTM Analysis 13

As noted in Section D above, the analysis of revenue from participating 14

customers fully supports continuation of this important job-promoting 15

program. To be sustainable going forward, however, the new program 16

must be supported by an evaluation of current marginal cost and rates. 17

PG&E’s analysis of the program on a forward-looking basis utilizes 18

schedule-average rates (based on rates effective May 1, 2020) and 19

marginal costs proposed in this proceeding.6 20

PG&E calculated the maximum rate reduction that could be applied to 21

each rate schedule on a schedule average basis for bundled customers 22

6 PG&E’s analysis includes several representative rate schedules as in the past. In

addition, PG&E has added the Small Light and Power (SLP) rate schedules reflecting their current eligibility for the program.

(PG&E-3)

7-18

using a conservative set of assumptions, meaning assumptions that would 1

tend to reduce the level of the maximum potential rate reduction. 2

Specifically, PG&E calculated the maximum available rate reduction by 3

subtracting the following components from the bundled bill: transmission 4

charges,7 generation marginal energy costs, constrained distribution 5

capacity costs,8 marginal customer access costs, and NBCs. In addition, 6

consistent with separately allocating the PCIA cost for bundled customers 7

(and reflecting the PCIA in tariffs for bundled customers), PG&E has 8

calculated the CTM by assuming that the bundled customer PCIA is an 9

NBC. As shown in Table 7-7, the maximum achievable rate reduction in 10

distribution constrained areas was less than the proposed 20 percent 11

maximum rate reduction for only SLP. Significantly, while the CTM is 12

generally positive when the 20 percent rate reduction is applied, the CTM 13

would be much greater for customers located in distribution areas that were 14

not subject to distribution capacity constraints (yielding a lower marginal 15

cost) or in cases where the lower 12 or 18 percent rate reduction are 16

applied. To illustrate the potential CTM in distribution areas that are 17

unconstrained, PG&E has also shown the maximum potential rate reduction 18

in unconstrained areas in Table 7-7. Thus, PG&E believes it is reasonable 19

to propose to retain the three rate reduction tiers, but will lower the 20

maximum rate reduction percentage from 25 percent to 20 percent; making 21

the three tiers 12 percent, 18 percent, and 20 percent. 22

7 Fully transmission charges are used as a substitute for marginal transmission costs in

this calculation. 8 A local distribution planning area is considered constrained, for purposes of evaluating

CTM for individual EDR participants, if it has planned capacity-related capital projects in excess of $1 million.

(PG&E-3)

7-19

TABLE 7-7 MAXIMUM POTENTIAL EDR RATE REDUCTION

Line No. Customer Class

Maximum Potential Rate Reduction

(Distribution Constrained Areas)

Maximum Potential Rate Reduction

(Distribution Unconstrained Areas)

1 SLP 1415.6% 28.930.1% 2 A-10/B-10S 21.13% 33.69% 3 E-19P/B-19P 20.43% 33.1% 4 E-19S/B-19S 28.1% 39.98% 5 E-20T/B-20T 20.42% 20.42% 6 E-20P/B-20P 20.421.6% 33.54% 7 E-20S/B-20S 24.825.5% 37.54%

One enhancement to the EDR Program required by D.13-10-019 was 1

to provide for specific treatment of rate reductions for Direct Access and 2

Community Choice Aggregation (DA/CCA) customers. As implemented, 3

rate reductions were applied separately to bundled customers and DA/CCA 4

customers by allocating the rate reduction to distribution and generation 5

charges. Schedule EDR currently provides the proportions that will be used 6

to allocate the rate reductions to the generation and distribution portions of 7

the bills. PG&E continues to believe this approach to deriving the rate 8

reductions to participating customers is appropriate. However, the original 9

proportions adopted in 2013 do not compare favorably with the CTM 10

analysis provided herein at transmission and primary service voltages. 11

Accordingly, PG&E proposes to revise those allocation factors in this 12

proceeding. The revised allocation factors are shown in Table 7-8, together 13

with the current values. 14

TABLE 7-8 REVISED ALLOCATION FACTORS OF EDR RATE REDUCTIONS TO GENERATION

AND DISTRIBUTION

Line No. Rate Reduction Component Transmission Primary Secondary

1 Generation Current 95% 70% 60% 2 Generation Proposed 8786% 60% 60% 3 Distribution Current 5% 30% 40% 4 Distribution Proposed 1314% 40% 40%

G. Compliance With EDR D.18-08-013 Requirements 15

Energy Usage Reduction Requirement and Audit 16

(PG&E-3)

7-20

The 2018-2020 EDR tariff states that during the third year of such EDR 1

agreements, such customers will be subject to an audit to determine 2

whether the energy usage reduction requirement has been met (see text 3

below). PG&E will be conducting these audits for projects that are in their 4

third year on the current EDR rate, which would occur in 2021 at the earliest. 5

Applications shall implement such measures such as those presented 6 by PG&E, to achieve a 5% energy usage reduction during the life of 7 EDR agreement. This energy usage reduction will be determined by 8 PG&E through an audit conducted by PG&E during the third year of the 9 agreement. If the audit shows Applicant has not yet achieved a 10 5% energy reduction, PG&E may discontinue the rate reduction benefit 11 for the remainder of the agreement, in PG&E’s discretion, or PG&E may 12 establish an action plan for the Applicant to achieve the required 13 5% energy usage reduction, including an additional audit early in year 14 five of the Agreement to ensure the requirement was met. 15

Third-Party Verification 16

The 2018-2020 EDR tariff states that customers on the EDR that are 17

projected to receive over $100,000 in savings will be subject to an annual, 18

after-the-fact economic impact audit by a third-party (see text below). As of 19

September 2019, none of the projects signed on the current EDR program 20

had projected savings greater than $100,000. PG&E will continue to 21

monitor each project for this $100,000 savings threshold and, in such 22

instances, have an economic impact audit conducted after one year on the 23

rate. The earliest this is anticipated to occur would be at the end of 2020, if 24

any applicable project is signed by the end of 2019. 25

EDR applicants who are projected by PG&E to receive over 26 one hundred thousand (100,000) dollars of savings per year from the 27 EDR program are subject to, and must agree to an annual, third-party, 28 after-the-fact EDR audit. The purpose of the audit is to verify 29 contribution to margin, the number of jobs created, wages and benefit 30 information, and document other indirect economic benefits to the 31 community. The third-party EDR audit will be conducted no sooner 32 than one (1) year after the customer’s EDR discount starts. 33

H. Conclusion 34

Since 2014, the EDR Program has helped create or retain over 14,000 jobs 35

for California and added over $8099.6 million of incremental, annual revenue 36

(including about $18.521 million of CTM) to lower the cost of the grid to all 37

ratepayers. The program’s rate reductions are also self-funding due to its 38

(PG&E-3)

7-21

positive CTM. To date, PG&E’s EDR Program has resulted in over $75 million 1

of combined wages and salary contribution to support California’s economy. 2

Because past program results show that the EDR has been beneficial to all 3

stakeholders within California, the Commission should therefore adopt PG&E’s 4

proposal to continue the EDR Program through 2023 presented herein. 5

(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 8

RATE PROGRAMS

FEES FOR SERVICES TO COMMUNITY CHOICE

AGGREGATION AND DIRECT ACCESS ELECTRIC SERVICE

PROVIDERS

(PG&E-3)

8-i

PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 8

RATE PROGRAMS FEES FOR SERVICES TO COMMUNITY CHOICE AGGREGATION AND DIRECT

ACCESS ELECTRIC SERVICE PROVIDERS

TABLE OF CONTENTS

A. Introduction ............................................................................................................ 8-1

B. Background............................................................................................................ 8-1

C. Proposed Fees and Rate Schedule Changes ..................................................... 8-3

D. Implementation and On-going Maintenance........................................................ 8-7

E. Conclusion ............................................................................................................. 8-7

(PG&E-3)

8-1

PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 8 2

RATE PROGRAMS 3

FEES FOR SERVICES TO COMMUNITY CHOICE AGGREGATION 4

AND DIRECT ACCESS ELECTRIC SERVICE PROVIDERS 5

A. Introduction 6

In this chapter, Pacific Gas and Electric Company (PG&E) sets forth its 7

proposals for changes to fees and respective Rate Schedules in the 2020 8

General Rate Case (GRC) Phase II for incremental services1 rendered to 9

principal energy providers under two alternative energy provider programs. The 10

remainder of this chapter is organized as follows: 11

Section B – Background 12

Section C – Proposed Fees and Rate Schedule Changes 13

Section D – Implementation and On-going Maintenance 14

Section E – Conclusion 15

Attachment A – Summary matrix of proposed fee changes per applicable 16

Rate Schedule in comparative format with current respective fees including 17

sample costs based on current labor rates and hour required for each 18

proposed “at cost” service and the methodology by which they would 19

be applied. 20

Attachment B – Recommended revisions to Schedule E-CCA. 21

Attachment C – Recommended revisions to Schedule E-ESP. 22

Attachment D – Recommended revisions to Schedule E-ESPNDSF. 23

B. Background 24

The idea of having independent non-utility entities as alternative electric 25

supply providers directly available to retail customers began to take shape in the 26

1990’s as part of the California’s interest to promote customer choice by 27

expanding market competition within the energy industry. 28

1 In D.04-12-046, the California Public Utilities Commission (Commission) held that

“individual CCAs should not assume the cost of developing the CCA program’s basic infrastructure,” but that individual CCAs should be charged for the cost of “specific specialized services.” (pp. 11-12).

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The Direct Access (DA) electric services program launched in 1998 and 1

allowed Energy Service Providers (ESP) to supply electric power directly to a 2

limited number of customers. The program currently has approximately 9,300 3

enrolled participants and is expected to grow. The program was recently 4

reopened to new customers under Decision (D.) 19-09-043. Terms and 5

conditions applicable to the DA program are contained primarily under PG&E’s 6

Electric Rule No. 22 with related program service fees authorized primarily under 7

Electric Schedule E-ESP and E-ESPNDSF. 8

The first Community Choice Aggregation (CCA) electric service provider 9

was established in 2010 and there are now 12 CCAs in operation as of 10

June 2019 serving approximately 3.0 million electric customers within PG&E’s 11

service territory. The number of CCA customers is expected to exceed 12

3.3 million by the end of 2020. Terms and conditions applicable to the CCA 13

program are reflected primarily under PG&E’s Electric Rule No. 23, with related 14

program service fees authorized primarily under Electric Schedule E-CCA. 15

Within each referenced Rate Schedule under both DA and CCA programs, 16

fees for services rendered to DA and CCA providers can be grouped into two 17

categories: (1) account-based, i.e., fees assessed based on the number of 18

accounts serviced, and (2) event-based, i.e., fees assessed based on 19

completing and/or delivering a specified task or product as requested by a DA or 20

CCA provider. 21

With the establishment of the DA and CCA programs at different inception 22

dates over a span of nearly twenty years and over the course of their combined 23

operational history of over 28 years from inception to date, updates to the 24

applicable Rate Schedules and respective fees for which PG&E is requesting 25

revisions in this proceeding, have been infrequent and limited. In 2001, PG&E 26

filed an application to reassess its DA and CCA service fees, 27

Application 11-12-009. PG&E reached a settlement agreement with 28

participating parties in that docket, which was approved by the Commission by 29

D.13-04-020. That Settlement included a consolidated and simplified fee 30

structure for selected account-based services, with provisions for yearly 31

escalations in fees. In the 2017 GRC Phase II proceeding, the Commission 32

adopted a settlement which revised the Meter Data Management Agent (MDMA) 33

fee, DA/CCA rate ready and bill ready billing fees and fees for DA meter 34

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services. That 2017 DA/CCA fees settlement primarily enabled the alignment of 1

similar account-based billing and MDMA services with similar fees between the 2

DA and CCA programs while also adjusting them downward due to the overall 3

customer growth with respect to the programs which enabled efficiencies to 4

be implemented. 5

In this proceeding, PG&E is proposing changes to the DA/CCA event-based 6

fees that were not updated in the 2017 GRC Phase II proceeding. While 7

updates to the service fees presented in this application have been limited over 8

the programs’ operational history, service delivery developments such as 9

technological advancements, process maturity, and procedural streamlines have 10

evolved over the years. These evolving developments in service delivery and 11

program maturity are the principal factors driving the fee changes proposed in 12

this chapter in an effort to capture the impacts to cost of services and to make 13

them current and sustainable for the future. 14

C. Proposed Fees and Rate Schedule Changes 15

The fee changes PG&E proposes here are primarily limited to certain 16

“event-based” services and are intended to standardize practices to support 17

tracking and billing based on actual labor costs incurred to perform each service 18

for each event. Proposed changes within Schedule E-ESPNDSF include 19

several fees related to “Account Analysis” services provided to ESPs currently 20

assessed on a per account, per report, or per occurrence basis. PG&E also 21

proposes to remove these variations by grouping them all as “Account 22

Assistance” services using the “at-cost” actual labor approach consistent with 23

how similar services are grouped and priced for CCA services within Schedule 24

E-CCA. This approach will support fees that are more sustainable given cost 25

fluctuations over time. Adoption of an “at cost” pricing approach for the 26

referenced services will not only reduce fee variations between the two 27

programs, effectively streamlining fees for similar services. It will also minimize 28

fee update/maintenance requirements and ultimately enable a more accurate 29

accounting and billing of services based on actual labor costs. 30

If approved, implementation of this “at cost” approach will require PG&E to 31

utilize standardized documented procedures and practices that require each 32

servicing personnel to track/record their respective time spent on each service 33

event. This ultimately enables real time cost management locally while ensuring 34

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only standard labor rates that are centrally maintained, current, and specific to 1

the servicing contributor(s) are applied to each service event on an ongoing 2

basis; that, in turn, will support a more accurate method to account and bill for 3

the respective services. Section D “Implementation and On-going Maintenance” 4

below discusses how we propose to implement this “at cost” approach, including 5

procedures for tracking and billing event based services using actual labor cost 6

of service. Event based services previously established with specific hourly fees 7

will effectively achieve realignment with this proposed “at cost” methodology. 8

Service fees under each Schedule for which a change is not being proposed 9

are not included. Fees not proposed for change are primarily account-based 10

fees, of which the related services are usually provided on a recurring cycle 11

basis and are accounted for and billed to the ESPs and CCAs programmatically 12

without the need to track separately, as labor rate and time are not major 13

factors. 14

Specific fee change proposals are presented below in a 6-columnar table 15

format to show for each applicable service, the respective rate schedule 16

reference, the current fee, proposed (“at-cost”) sample fee, and an example of 17

the actual labor cost calculated based on current factors such as 2019 standard 18

labor rates (consistent with approved GRC cost funding mechanisms) for each 19

applicable servicing line of business(s), applied to current estimated labor hours 20

to fulfill each service, and are organized by fee schedule under each program as 21

follows: 22

Community Choice Aggregation Program 23

Table 8-1: Electric Schedule E-CCA 24

DA ESP Program 25

Table 8-2: Electric Schedule E-ESP. Table 8-2 also reflects the 26

deletion of certain rate programs for Electric Schedule E-ESP, 6.A.5 27

which has never been used. 28

Table 8-3: Electric Schedule E-ESPNDSF. Proposed changes to this 29

schedule also reflects the consolidation of certain rate programs for 30

Electric Schedule E-ESPNDSF 3A. See Attachment D. 31

While the tables presented below provide a comparative view between the 32

current fee and the proposed change including estimated cost impact for each 33

applicable service, the matrix provided by Attachment A of this chapter offers 34

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8-5

more details to support the illustrative costs estimated for each service using the 1

proposed fee methodology, including estimated labor hours required to perform 2

each service as well as the 2019 standard labor rate specific for the department 3

personnel that performs each service. This Attachment A will also be used (and 4

expanded on as necessary) as part of the supporting workpapers to this chapter. 5

PG&E’s recommended changes to the affected rate schedules are provided as 6

attachments to this chapter: Schedule E-CCA is provided as Attachment B; 7

Schedule E-ESP is provided as Attachment C; and Schedule E-ESPNDSF is 8

provided as Attachment D. 9

COMMUNITY CHOICE AGGREGATION PROGRAM TABLE 8-1

ELECTRIC SCHEDULE E-CCA

Line No. Service Description

Tariff Reference Fee Type

Current Fee

Proposed “At Cost” Labor Per Hour(a)

Effective Cost Example(a)

1 CCA Service Establishment Sheet 1: 1 Per Hour $119.58 to $149.48

$109.50 to $154.03

N/A

2 Customer List Development Sheet 2: 2c Per Data Extract

$2,596 $109.50 $438

3 Mass Enrollment Sheet 2: 3 Per Event $4,475 $154.03 $3,081

4 MDMA Services

5 Reposting Monthly Meter Data Sheet 5: 6c Per Meter Read $20.84 $137.94 (b)

6 Reposting of Account Usage (12-month history)

Sheet 5: 6d Per Hour $104.25 $137.94 N/A

7 Account Assistance Sheet 5: 6e Per Hour $104.25 $133.63 N/A

8 Other Billing Services

9 CCA Rate Schedule Value UsageChange

Sheet 6: 6b Per EventHour N/A $153154.03 N/A

10 Programming for Consolidated Billing

Sheet 7: 9a Per Hour $97.84 $154.03 N/A

11 Account Assistance Sheet 7: 9d Per Hour $69.30 $112.20 to $137.94

N/A

12 CCA Termination of Service

13 Voluntary Termination Sheet 8: 10a Per Event $4,475 $154.03 $6,161 14 Standard Phase-in Services Sheet 8: 11 Per Phase-in $4,475 $154.03 $5,391

_______________

(a) Labor rates and effective costs are presented as examples using applicable 2019 data. The labor rates presented vary by service because they are specific to the cost unit that performs each service. A range is provided if the service requires performance by more than one cost unit. See Attachment A of this chapter for sample calculation supporting these examples including estimated labor hours to complete a typical request of each applicable service. Also see Section D “Implementation and On-going Maintenance” below for discussion of proposed cost tracking and update procedures.

(b) Effective cost for these services as proposed will be based on total labor hours required per event, which may include servicing multiple accounts or reports.

(PG&E-3)

8-6

DIRECT ACCESS ENERGY SERVICE PROVIDER PROGRAM TABLE 8-2

ELECTRIC SCHEDULE E-ESP

Line No. Service Description

Tariff Reference Fee Type

Current Fee

Proposed “At Cost” Labor Per Hour(a)

Effective Cost Example(a)

1 Consolidated PG&E Billing - Rate Ready Billing Set-Up Charges

2 Programming for Consolidated Billing Set-Up

Sheet 3: 6A5a Per Hour $123.80 $154.03 N/A

3 Programming for ESP’s Rate Schedules - Standard Rate Structure

Sheet 3: 6A5b Per Hour $123.80 $154.03 N/A

4 Programming for ESP’s Rate Schedules - Custom Rate Structure

Sheet 3: 6A5c Per Hour $146.15 (See Attachment C)

N/A

5 Programming for ESP’s Bill Messages

Sheet 3: 6A5d Per Hour $123.80 $154.03 N/A

6 Consolidated PG&E Billing - Bill Ready Billing Set-Up Charges

7 Programming for Consolidated Billing Set-Up

Sheet 4: 6B4a Per Hour $123.80 $154.03 N/A

8 Programming for ESP’s Bill Messages

Sheet 4: 6B4b Per Hour $123.80 $154.03 N/A

_______________

(a) Labor rates and effective costs are presented as examples using applicable 2019 data. The labor rates presented vary by service because they are specific to the cost unit that performs each service. A range is provided if the service requires performance by more than one cost unit. See Attachment A of this chapter for sample calculation supporting these examples including estimated labor hours to complete a typical request of each applicable service. Also see Section D “Implementation and On-going Maintenance” below for discussion of proposed cost tracking and update procedures.

(PG&E-3)

8-7

DIRECT ACCESS ENERGY SERVICE PROVIDER PROGRAM TABLE 8-3

ELECTRIC SCHEDULE E-ESPNDSF

Line No. Service Description

Tariff Reference Fee Type

Current Fee

Proposed “At Cost” Labor Per

Hour(a) Effective Cost

Example(a)

1 Full Consolidated ESP Billing

2 Billing Set-Up and Ongoing Support Sheet 1: 1A Per Hour $134.57 $154.03 N/A

3 Exception Fees - Account Analysis

4 Retrieval of Account Information Sheet 2: 3A1 Per Account $5.00 $112.20 (b) 5 Routine Account Analysis Sheet 2: 3A2 Per Account $15.83 $112.20 (b) 6 Complex Account Analysis Sheet 2: 3A3 Per Hour $63.81 $133.63 N/A 7 Resend File/Report Sheet 2: 3A4 Per Report $15.00 $112.20 (b) 8 Investigate EDI Duplicate Payments Sheet 2: 3A5 Per Occurrence $134.57 $137.94 $137.94 9 Refund Account Credits Due to

Overpayment Sheet 2: 3A6 Per Account $5.00 $112.20 (b)

_______________

(a) Labor rates and effective costs are presented as examples using applicable 2019 data. The labor rates presented vary by service because they are specific to the cost unit that performs each service. A range is provided if the service requires performance by more than one cost unit. See Attachment A of this chapter for sample calculation supporting these examples including estimated labor hours to complete a typical request of each applicable service. Also see Section D “Implementation and On-going Maintenance” below for discussion of proposed cost tracking and update procedures.

(b) Effective cost for these services as proposed will be based on total labor hours required per event which may include servicing multiple accounts or reports.

D. Implementation and On-going Maintenance 1

If approved, this methodology of applying current labor rates to bill for 2

services will require implementation of new procedures. The required 3

procedures will include at minimum, each department responsible for performing 4

a service to track the actual time it takes to complete each task using internal 5

tracking order numbers established for each service. Standard labor rates 6

maintained by our SAP system will automatically apply to generate monthly bills 7

which will be quality reviewed prior to transmitting to respective CCA and DA 8

providers. In addition, Commission authorized advice letter filings will be used 9

as needed to propose additional updates. PG&E proposes that the new rates 10

could go into effect no later than the beginning of the third calendar month after 11

the supporting business processes and systems are in place to enable the new 12

procedures to be implemented into operational practice. 13

E. Conclusion 14

For all of the foregoing reasons, PG&E requests that the Commission adopt 15

its proposed DA and CCA Service Fees, for all applicable rate schedules. In 16

addition, PG&E acknowledges the need for regular reassessments of these fees 17

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8-8

on an ongoing schedule to ensure program sustainability and thus anticipates 1

that updates may be required in future rate design proceedings or Tier 2 advice 2

letter filings. 3

(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 8

ATTACHMENT A

FEES FOR SERVICES TO CCA AND DA

ELECTRIC SERVICE PROVIDERS

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8-AtchA-1

(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 8

ATTACHMENT B

RECOMMENDED REVISIONS TO

ELECTRIC SCHEDULE E-CCA – SERVICES TO

COMMUNITY CHOICE AGGREGATORS

U 39 San Francisco, California

Revised Cal. P.U.C. Sheet No. 35797-ECancelling Revised Cal. P.U.C. Sheet No. 34579-E

ELECTRIC SCHEDULE E-CCA Sheet 1SERVICES TO COMMUNITY CHOICE AGGREGATORS

(Continued)

Advice 4741-E Issued by Date Filed November 20, 2015Decision 13-04-020 Steven Malnight Effective January 1, 2016

Senior Vice President ResolutionRegulatory Affairs

APPLICABILITY: This schedule applies to Community Choice Aggregators (CCAs) who participate in Community Choice Aggregation Service (CCA Service) and to customers who receive CCA Service, pursuant to California Public Utilities Commission Decision 05-12-041 and electric Rules 1 and 23.

TERRITORY: The entire PG&E service territory.

RATES: 1. CCA SERVICE ESTABLISHMENT

This fee will apply when a CCA establishes service. This fee will cover thecost of establishing a new business relationship with the CCA and willinclude activities such as establishing a CCA account in PG&E’s customerinformation system for customer switching, meter reading, and billingservices, EDI testing and processing forms and agreements, including butnot limited to: the CCA Service Agreement, the CCA Information Form,the Credit Application, the Electronic Funds Transfer Agreement, andprovides for a review of a CCA’s credit worthiness. Charges are based onan hourly rate required to perform the activities.

Fee........................................................... $119.58-$149.48 per hourLabor (I)

2. CUSTOMER NOTIFICATION (OPTIONAL SERVICE)

a. CUSTOMER NOTIFICATION – DIRECT MAIL

This service provides a direct mail customer notification service(labeling and mailing of notifications). This service will be applicableto the initial customer notifications and to follow-up notifications.

Fee ....................................................................... Labor and Material

b. CUSTOMER NOTIFICATION – NOTIFICATION IN MONTHLY PG&EBILL

The CCA may request PG&E to mail the CCA notices in PG&E’smonthly bills to the customers. PG&E will perform this service andcharge the CCA based on labor and material costs, and anyadditional postage required to mail the monthly bills. This serviceshall be subject to advance notice and scheduling requirements,PG&E’s normal bill insert business practices, and operationalspecifications. CCA customer notices inserted in PG&E’s billingenvelope shall include a disclaimer prominently displayed in font nosmaller than the title or heading of the customer notices stating: "Thisnotice was prepared and paid for by [CCA name] and not PG&E."Information contained in such notices shall be limited to that requiredby PU Code Section 366.2(c)(13)(A).

Fee ....................................................................... Labor and Material

Postage ................................................................ Additional Postage

(PG&E-3)

8-AtchB-1

U 39 San Francisco, California

Revised Cal. P.U.C. Sheet No. 35798-ECancelling Revised Cal. P.U.C. Sheet No. 34580-E

ELECTRIC SCHEDULE E-CCA Sheet 2SERVICES TO COMMUNITY CHOICE AGGREGATORS

(Continued)

Advice 4741-E Issued by Date Filed November 20, 2015Decision 13-04-020 Steven Malnight Effective January 1, 2016

Senior Vice President ResolutionRegulatory Affairs

RATES:(Cont’d.)

2. CUSTOMER NOTIFICATION (OPTIONAL SERVICE) (Cont’d.)

c. CUSTOMER LIST DEVELOPMENT

PG&E will perform a data extract to provide a list of customers with astandard set of data elements. Based upon the CCA’s specific criteria, thelist can be refined and finalized to specify the customers that will receive anotification. This fee is calculated based upon a per event basis and is basedon labor costs to perform a data extract with a standard set of data elements.No material costs are included in this fee.

Fee...................................................................$2,596 per data extractLabor

d. DESIGN CUSTOMIZED CUSTOMER NOTIFICATION

This service provides special design or customization for the customernotifications as specified by the CCA.

Fee...................................................................................Labor and Material

3. MASS ENROLLMENT

This fee will apply to a CCA. Upon completion of the initial customer notificationand opt-out period, PG&E will initiate a mass transfer of the eligible customers(who have not opted-out) onto CCA Service over one-billing cycle period on thecustomer’s regularly scheduled meter read date (assuming no metering work isrequired), and send a confirmation to the CCA through the CCASR process.

Fee .....................................................................................$4,475 per eventLabor

4. OPT-OUT REQUESTS

These service fees will apply to a CCA and are associated with processingcustomer requests for opting-out of the CCA program. PG&E will offer two optionsto process responses by customers to the “opt-out” notifications: Internet andAutomated Telephone service.

a. INTERNET OPT-OUT – This fee will apply when a customer opts out of aCCA’s Program using the Internet through PG&E’s website.

Internet Opt-out................................................................ .$0.49 per account

b. AUTOMATED TELEPHONE (IVRU) OPT-OUT – This fee will apply when acustomer opts out of a CCA’s program using PG&E’s Interactive VoiceResponse Unit (IVRU).

Automated Telephone (IVRU) Opt-Out ............................ .$0.42 per account

(I)

(I)

(PG&E-3)

8-AtchB-2

U 39 San Francisco, California

Revised Cal. P.U.C. Sheet No. 35799-ECancelling Revised Cal. P.U.C. Sheet No. 34581-E

ELECTRIC SCHEDULE E-CCA Sheet 3SERVICES TO COMMUNITY CHOICE AGGREGATORS

(Continued)

Advice 4741-E Issued by Date Filed November 20, 2015Decision 13-04-020 Steven Malnight Effective January 1, 2016

Senior Vice President ResolutionRegulatory Affairs

RATES:(Cont’d.)

5. COMMUNITY CHOICE AGGREGATION SERVICE REQUEST (CCASR)

a. CCASR

This fee will apply to a CCA when a Connect or Disconnect CCASR issubmitted by a CCA.

Per account per CCASR submittal........................................................$0.79

b. CUSTOMER RE-ENTRY

This charge is imposed on the customer. This fee covers the cost ofprocessing customer requests to switch back to PG&E Bundled Serviceafter the Opt-Out period has expired.

Fee......................................................................................... .$4.24 account

c. NEW CUSTOMER

This fee will apply to a CCA to cover PG&E’s cost to enroll a new accountonto CCA Service after mass enrollment has occurred.

Fee................................................................................... $0.49 per account.......................................................................................................................

(I)

(I)

(PG&E-3)

8-AtchB-3

U 39 San Francisco, California

Revised Cal. P.U.C. Sheet No. 41757-ECancelling Revised Cal. P.U.C. Sheet No. 35800-E

ELECTRIC SCHEDULE E-CCA Sheet 4SERVICES TO COMMUNITY CHOICE AGGREGATORS

(Continued)

Advice 5225-E Issued by Date Filed February 9, 2018Decision 18-01-013 Robert S. Kenney Effective March 1, 2018

Vice President, Regulatory Affairs Resolution

RATES:(Cont’d.)

6. METER DATA MANAGEMENT AGENT (MDMA) SERVICES

a. METER DATA POSTING

This service provides meter data to the CCA. Meter data will be madeavailable to the CCA in EDI 867 format, and will be posted for retrievalby the CCA on PG&E’s Data Exchange Server (DES).

Composite MDMA fee per meter per month ............................. $0.14

b. UNSCHEDULED METER READ

This fee will apply when a CCA requests cumulative reads or intervalusage data for an account for a period outside the normal PG&E meterreading schedule. PG&E will attempt to accommodate requests forunscheduled reads. In no case will PG&E provide cumulative readsand/or interval usage data for a period greater than 33 contiguous days.

Per unscheduled meter read per cumulative meter ..............no charge

Per unscheduled meter read per interval meter....................no charge

(N)

(PG&E-3)

8-AtchB-4

San Francisco, California

Cal. P.U.C. Sheet No.Cancelling Cal. P.U.C. Sheet No.

Advice Issued by Date Filed Decision Steven Malnight Effective

Senior Vice President Resolution Regulatory Affairs

(PG&E-3)

8-AtchB-5

U 39 San Francisco, California

Revised Cal. P.U.C. Sheet No. 41758-ECancelling Revised Cal. P.U.C. Sheet No. 35802-E

ELECTRIC SCHEDULE E-CCA Sheet 6SERVICES TO COMMUNITY CHOICE AGGREGATORS

(Continued)

Advice 5225-E Issued by Date Filed February 9, 2018Decision 18-01-013 Robert S. Kenney Effective March 1, 2018

Vice President, Regulatory Affairs Resolution

RATES:(Cont’d.)

7. CONSOLIDATED BILL-READY BILLING SERVICES

a. CONSOLIDATED PG&E BILLING

Composite Bill-Ready Billing Fee

This fee covers the cost to present the CCA’s energy and customer charges.It also includes cost to process the CCA’s energy charges and customerpayments.

Per account per billing cycle........................................................$0.21 (R)

8. CONSOLIDATED RATE-READY BILLING SERVICES

a. CONSOLIDATED PG&E BILLING

Composite Rate-Ready Billing Fee

This fee covers the cost to present the CCA’s energy and customer charges on an additional bill page. It also includes cost to process the CCA’s energy charges and customer payments, and respond to CCA calls regarding billing issues.

Bill presentation and processing of CCA's energy charges and customer payments, per account per billing cycle ......................................$0.21

b. CCA RATE SCHEDULE VALUE CHANGE

This fee will apply to a CCA when they request PG&E to change the CCA’sprice on a particular rate schedule or change the rate schedule assigned to aparticular CCA customer.

Fee .............................................................................. no chargeLabor

(R)

(PG&E-3)

8-AtchB-6

U 39 San Francisco, California

Revised Cal. P.U.C. Sheet No. 35803-ECancelling Revised Cal. P.U.C. Sheet No. 34585-E

ELECTRIC SCHEDULE E-CCA Sheet 7SERVICES TO COMMUNITY CHOICE AGGREGATORS

(Continued)

Advice 4741-E Issued by Date Filed November 20, 2015Decision 13-04-020 Steven Malnight Effective January 1, 2016

Senior Vice President ResolutionRegulatory Affairs

RATES:(Cont’d.)

9. OTHER BILLING SERVICES

a. PROGRAMMING FOR CONSOLIDATED BILLING

This fee will apply to a CCA when they request PG&E to provide additional billing services requiring programming such as text messages on the page of the bill presenting the CCA’s charges.

Fee .................................................................... $97.84 per hourLabor

b. BILL ADJUSTMENT

This fee will apply when a CCA requests PG&E to adjust a CCA customer’s bill for reason unrelated to the CCA’s charges, such as the following:

– Goodwill gesture or promotional discounts

– Recourse adjustments as a result of dispute resolution

– Policy adjustment to satisfy a customer’s complaint

Fee ....................................................................................... no charge

c. CCA RETURN PAYMENT

This fee will apply to a CCA when a CCA’s check is returned for payment of any of PG&E’s service charges.

Fee .............................................................................. $8.00 per event

d. ACCOUNT ASSISTANCE

This fee will apply to a CCA when a CCA requests PG&E to perform other types of account assistance. For example: switch date corrections, reconciliation of balances and statements, duplicate bills,routine or complex account analyses, retrieval of account information, reproduction/resending of file/report, investigating EDI duplicate payments, and refunding account credits due to overpayments. and account analysis.

Fee .................................................................... $69.30 per hourLabor

(I)

(I)

(PG&E-3)

8-AtchB-7

U 39 San Francisco, California

Revised Cal. P.U.C. Sheet No. 35804-ECancelling Revised Cal. P.U.C. Sheet No. 34586-E

ELECTRIC SCHEDULE E-CCA Sheet 8SERVICES TO COMMUNITY CHOICE AGGREGATORS

Advice 4741-E Issued by Date Filed November 20, 2015Decision 13-04-020 Steven Malnight Effective January 1, 2016

Senior Vice President ResolutionRegulatory Affairs

RATES:(Cont’d.)

10. CCA TERMINATION OF SERVICE

a. VOLUNTARY TERMINATION

This charge will apply when a CCA terminates its entire program on avoluntary basis as described in Rule 23. If the CCA requests PG&E toprovide the required notifications, then a separate CCA Customer NotificationFee will be applicable. The Voluntary Termination Fee would be assessed ona per event basis.

Fee.............................................................................$4,475 per eventLabor

b. INVOLUNTARY TERMINATION

This fee will apply under conditions associated with Involuntary ServiceChanges as defined in Rule 23. All associated costs will be assessed to theCCA on a time and material basis in the event of such a circumstance.

Fee...................................................................................Labor and Material

11. STANDARD PHASE-IN SERVICES

This charge will apply when a CCA requests Phase-In Services as set forth inRule 23. A CCA may select one of the following phase-in options: customer class,rate class, incorporated city, county, or zip code. The Phase-In requires theaffected customers in each phase to be mass enrolled in CCA Service on thecustomer’s regularly scheduled meter read date over one-billing cycle and requiresthe CCA to conclude its phase-in plan within one CRS period beginning with thefirst phase-in event. A CCA may also select a customized phase-in which wouldbe provided under Specialized Services.

Fee ................................................................................$4,475 per phase-inLabor

12. SPECIALIZED SERVICES

This charge will apply when a CCA requests Specialized Services, includingPhase-In Services as set forth in Rule 23. This fee will also apply in the event aCCA requests Boundary Metering as set forth in Rule 23. This service will beprovided on terms mutually agreeable to PG&E and the CCA. The fee will becalculated on a time and material basis.

Fee ...........................................................................................Labor and Material

(I)

(I)

SPECIAL CONDITIONS:

1. DEFINITIONS

a. Account – In PG&E’s customer information system, a service account iscalled a service agreement and is defined as the customer’s serviceidentification number linking the customer’s service with a specific meter.

(PG&E-3)

8-AtchB-8

(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 8

ATTACHMENT C

RECOMMENDED REVISIONS TO

ELECTRIC SCHEDULE E-ESP – SERVICES TO

SERVICE PROVIDERS

U 39 San Francisco, California

Revised Cal. P.U.C. Sheet No. 41771-ECancelling Revised Cal. P.U.C. Sheet No. 35805-E

ELECTRIC SCHEDULE E-ESP Sheet 1SERVICES TO ELECTRIC SERVICE PROVIDERS

(Continued)

Advice 5225-E Issued by Date Filed February 9, 2018Decision 18-01-013 Robert S. Kenney Effective March 1, 2018

Vice President, Regulatory Affairs Resolution

APPLICABILITY: This schedule applies to Electric Service Providers (ESPs) who provide direct access service to Customers, as defined in electric Rule 1 and Rule 22.

TERRITORY: The entire PG&E service territory.

RATES: 1. METER INSTALLATION

If an ESP requests that PG&E install a meter for its Direct Access Customer, therates will be as set forth in Schedule E-EUS.

2. METER TESTING

If an ESP requests that PG&E test a meter for its Direct Access Customer, therates will be as set forth in Schedule E-EUS.

3. METER REMOVAL

If an ESP requests that PG&E remove the existing PG&E meter, as set forth inRule 22, the charge shall be as set forth in Schedule E-EUS.

4. INSPECTION OF ESP-INSTALLED METERING EQUIPMENT

If PG&E inspects ESP-installed metering equipment pursuant to Rule 22 and theESP Service Agreement, the charge shall be as set forth in Schedule E-EUS.

5. METER DATA MANAGEMENT AGENT (MDMA) SERVICES

a. MDMA services include meter reading setup, if required, to ensure theESP’s meter communication system is compatible with PG&E’s meterreading system, data validation, editing and estimating to settlement qualityform, data reads and data transfer to the MDMA Server.

If PG&E performs MDMA services for an ESP the charge shall be:

MDMA Composite Fee per meter per month ......................... $0.14 (R) (T)

(PG&E-3)

8-AtchC-1

U 39 San Francisco, California

Revised Cal. P.U.C. Sheet No. 41772-ECancelling Revised Cal. P.U.C. Sheet No. 35806-E

ELECTRIC SCHEDULE E-ESP Sheet 2SERVICES TO ELECTRIC SERVICE PROVIDERS

(Continued)

Advice 5225-E Issued by Date Filed February 9, 2018Decision 18-01-013 Robert S. Kenney Effective March 1, 2018

Vice President, Regulatory Affairs Resolution

RATES: (Cont’d.)

6. CONSOLIDATED PG&E BILLING

A. Rate-Ready Billing

If an ESP requests that PG&E calculate the charge and bill the ESP’s DirectAccess Customers for the energy supply portion of the Customer’s bill, theprices shall be:

1) Composite Billing Fee, per service account per billing cycle……$0.21

If PG&E is billing the ESP’s Direct Access Customers for the energy supply portion of the Customer’s bill, the ESP may request that PG&E provide thefollowing additional billing-related services (Items 2 to 4) at no additional charge and is included in the Composite Billing Fee.

2) Duplicate Bill Request from ESP

3) Bill Adjustment

An ESP may request PG&E to adjust a Customer’s bill for reasonsunrelated to PG&E’s calculation of the ESP’s charges, such as thefollowing:

a) ESP requested adjustment for reasons unrelated to the bill, such asa goodwill gesture or promotional discount.

b) Recourse adjustment as a result of dispute resolution.

c) Policy adjustment to satisfy a Customer’s complaint.

(R)

(PG&E-3)

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San Francisco, California

Cal. P.U.C. Sheet No.Cancelling Cal. P.U.C. Sheet No.

Advice Issued by Date Filed Decision Steven Malnight Effective

Senior Vice President Resolution Regulatory Affairs

8-AtchC-3

(PG&E-3)

U 39 San Francisco, California

Revised Cal. P.U.C. Sheet No. 41773-ECancelling Revised Cal. P.U.C. Sheet No. 35808-E

ELECTRIC SCHEDULE E-ESP Sheet 4SERVICES TO ELECTRIC SERVICE PROVIDERS

(Continued)

Advice 5225-E Issued by Date Filed February 9, 2018Decision 18-01-013 Robert S. Kenney Effective March 1, 2018

Vice President, Regulatory Affairs Resolution

RATES: (Cont’d.)

6. CONSOLIDATED PG&E BILLING (Cont’d.)

B. Bill-Ready Billing

If an ESP requests that PG&E bill the ESP’s Direct Access Customers for theenergy supply portion of the Customer’s bill as calculated by the ESP, the pricesshall be:

1) Composite Billing Fee, per service account per billing cycle ........... $0.21

Per additional page per service account per billing cycle ......... no charge

2) Duplicate Bill Request, per bill per account .............................. no charge

3) Bill Adjustment, per adjustment per service account ................ no charge

An ESP may request PG&E to adjust a previously billed Customer’s bill due to the following reasons:

a. Recourse adjustment as a result of a dispute resolution

b. Policy adjustment to satisfy a Customer’s complaint

4) Bill-Ready Billing Set-Up Charges

a. Programming for consolidated bill set-up, per hour ....$123.80Labor

b. Programming for ESP’s bill message, per hour ..........$123.80Labor

c. ESP bill message text, per character................................ no charge

d. Central Processing Unit (CPU) charge forconsolidated bill programming, flat fee per ESP............... no charge

e. Computer Storage Device, per service accountbeing billed based on hourly interval metering data ......... no charge

(R)

(PG&E-3)

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U 39 San Francisco, California

Revised Cal. P.U.C. Sheet No. 32799-ECancelling Revised Cal. P.U.C. Sheet No. 32700-E

ELECTRIC SCHEDULE E-ESP Sheet 5SERVICES TO ELECTRIC SERVICE PROVIDERS (T)

Advice 4270-E Issued by Date Filed August 29, 2013Decision Brian K. Cherry Effective August 29, 2013

Vice President ResolutionRegulatory Relations

RATES:(Cont’d.)

7. DELIVERY OF MANDATED NOTICES

A. Electronic transmission of text (electronic mail) formandated notice ......................................................................no charge

8. LATE PAYMENT FEE

a. If an ESP is performing Consolidated ESP billing and the bill to PG&E is notpaid within 17 calendar days of transmittal of PG&E’s customer charges,PG&E will assess late charges at the rate of one percent per month of theoutstanding balance owed to PG&E, as set forth in the ESP ServiceAgreement.

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(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 8

ATTACHMENT D

ELECTRIC SCHEDULE E-ESPNDSF – ELECTRIC SERVICE

PROVIDER NON-DISCRETIONARY SERVICE FEES

U 39 San Francisco, California

Revised Cal. P.U.C. Sheet No. 32800-ECancelling Revised Cal. P.U.C. Sheet No. 30394-E

ELECTRIC SCHEDULE E-ESPNDSF Sheet 1ELECTRIC SERVICE PROVIDER NON-DISCRETIONARY SERVICE FEES (T)

(Continued)

Advice 4270-E Issued by Date Filed August 29, 2013Decision Brian K. Cherry Effective August 29, 2013

Vice President ResolutionRegulatory Relations

APPLICABILITY: This schedule applies to Electric Service Providers (ESPs) who provide direct access service to Customers, as set forth in Rule 22.

(T)

TERRITORY: The entire PG&E service territory.

RATES: 1. FULL CONSOLIDATED ESP BILLING

The following fees apply to ESPs performing Full Consolidated Billing whenassistance is requested from PG&E.

A. Billing set up and ongoing support (labor), per hour ............... $................................................................................................ 134.57cost

B. Billing set up and ongoing support (non-labor) ....................... cost

2. PARTIAL CONSOLIDATED ESP BILLING

A. ESPs Using VAN Transmission

The following fees apply to ESPs performing Partial Consolidated Billingthat are using VAN transmission.

Charge per account, per month $ 0.12Charge per ESP, per month $63.00

B. ESPs Not Using VAN Transmission

The following fees apply to ESPs performing Partial Consolidated Billingthat are not using VAN transmission.

Charge per ESP, per month $60.80

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8-AtchD-1

U 39 San Francisco, California

Revised Cal. P.U.C. Sheet No. 32801-ECancelling Revised Cal. P.U.C. Sheet No. 30395-E

ELECTRIC SCHEDULE E-ESPNDSF Sheet 2ELECTRIC SERVICE PROVIDER NON-DISCRETIONARY SERVICE FEES (T)

Advice 4270-E Issued by Date Filed August 29, 2013Decision Brian K. Cherry Effective August 29, 2013

Vice President ResolutionRegulatory Relations

RATES: (Cont’d.)

3. EXCEPTION FEES

The following fees apply to ESPs for services provided by PG&E.

A. Account AnalysisAssistance

This fee will apply to an ESP when an ESP requests PG&E to perform other types of account assistance. For example, switch date corrections, reconciliation of balances and statements, duplicate bills, routine or complex account analyses, retrieval of account information, reproduction/resending of file/report, investigating EDI duplicate payments, and refunding account credits due to overpayments.

Fee………………………………………………………………………Labor

1) Retrieval of account information, per account .....................$ 5.00

2) Routine account analysis, per account ................................$ 15.83

3) Complex account analysis, per hour............................... $ 63.81

4) Resend file/report, per report ...............................................$ 15.00

5) Investigate EDI duplicate payments, per occurrence…….. $134.57

6) Refund account credits due to overpayment, per account ..$ 5.00

B. Involuntary Billing Change

Billing/Accounts switch, per account............................................$ 8.00

(PG&E-3)

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(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 9

ELECTRIC ESSENTIAL USE STUDY FOR RESIDENTIAL

CUSTOMERS

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9-i

PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 9

ELECTRIC ESSENTIAL USE STUDY FOR RESIDENTIAL CUSTOMERS

TABLE OF CONTENTS

A. Introduction ....................................................................................................... 9-1

B. Joint Investor-Owned Utilities (IOU) Recommend Conducting a Single Electric Essential Use Study ............................................................................. 9-1

C. Joint IOU Request for a Consolidated, Bifurcated Track for Essential Use Study Proceeding Granted ............................................................................... 9-2

D. Consultation with Interested Parties in Development of Study Plan ................. 9-2

E. Cost-Tracking for the Electric Essential Use Study .......................................... 9-3

F. Conclusion ........................................................................................................ 9-3

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9-1

PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 9 2

ELECTRIC ESSENTIAL USE STUDY FOR RESIDENTIAL 3

CUSTOMERS 4

A. Introduction 5

Ordering Paragraph (OP) 14 of California Public Utilities Commission 6

(CPUC or Commission) Decision (D.) 18-08-013, issued August 17, 2018, 7

directed Pacific Gas and Electric Company (PG&E): 8

to develop a study plan (including budget) for developing a model of what 9 constitutes essential use for its residential customers. This model must be 10 developed using research, both existing (information sources such as the 11 Residential Appliance Saturation Survey (RASS) and Experian data) and 12 new direct customer surveys, to collect information on household size (in 13 terms of both square footage and number of residents), building features 14 (age, construction materials, insulation, etc.), and appliances (efficiency and 15 usage) in order to better evaluate the essential electricity needs of PG&E’s 16 residential customers. This model of essential usage must be able to 17 specify the amount of essential usage in both summer and winter for 18 residential customers separately in each of the hot climate zone (baseline 19 territories R, S, W, and P), the warm climate zone (baseline territories X 20 and Y), and the cool climate zone (baseline territories T, V, and Z).1 21

The decision also required that the Essential Use Study (EUS) Plan be 22

submitted with PG&E’s next General Rate Case (GRC) Phase II application, 23

scheduled to be filed November 22, 2019.”2 24

B. Joint Investor-Owned Utilities (IOU) Recommend Conducting a Single 25

Electric Essential Use Study 26

The Commission issued a similar requirement to quantify the amount of 27

electricity usage that should be deemed essential for the residential customers 28

of Southern California Edison Company (SCE) in D.18-11-027, issued 29

1 D.18-08-013, p. 179. 2 D.18-08-013 ordered that “[t]he study plan for the development of this model must be

submitted with PG&E’s next GRC Phase II application. PG&E shall consult with parties to this proceeding, if a party expresses interest, when developing this study plan. If the development of a model of essential usage is included in the scope of Rulemaking 18-07-006 before PG&E files its next GRC Phase II application, PG&E is not required to file the study plan in its next GRC Phase II application.” (D.18-08-013, OP 14, p. 179.)

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9-2

November 29, 2018. The Commission issued a similar requirement to develop 1

an essential usage study for the residential customers of San Diego Gas & 2

Electric Company (SDG&E), consistent with the directions as provided to PG&E 3

in D.18-03-013, in a Ruling issued November 1, 2019.3 PG&E, SCE and 4

SDG&E (collectively the Joint IOUs) have agreed that conducting the Essential 5

Use Study jointly will provide several benefits, including: cost sharing, 6

cost-effectiveness, stakeholder involvement, and consistency in methodology. 7

C. Joint IOU Request for a Consolidated, Bifurcated Track for Essential Use 8

Study Proceeding Granted 9

In its November 22, 2019 GRC Phase II Application (A.)19-11-019, PG&E 10

submitted the Joint IOUs’ initial EUS plan (as Attachment A to Chapter 9), and 11

proposed that the CPUC issue a ruling expediting and bifurcating the Joint EUS 12

from the other issues in the Phase II proceeding. In February 2020, the 13

Assigned Commissioner and Administrative Law Judge (ALJ) issued a Scoping 14

Memo and Ruling (“February Ruling”) which granted that request, and 15

consolidated CPUC consideration of the Joint IOUs’ EUS Plan (Joint Study) by 16

ordering SCE and SDG&E to file for party status and participate in this bifurcated 17

expedited EUS portion of PG&E’s 2020 GRC Phase II proceeding. 18

D. Consultation with Interested Parties in Development of Study Plan 19

In OP 14 of D.18-08-013, the Commission required PG&E to consult with 20

parties when developing its Essential Use Study (Study) plan. In OP 14 of 21

D.18-03-013, the Commission required SCE to consult with parties, including 22

PG&E, when developing its essential use study plan. In its ALJ Ruling issued on 23

November 1, 2019, the Commission required SDG&E to participate in PG&E’s 24

and SCE’s stakeholder participation process for developing a model of what 25

constitutes essential use for its residential customers. 26

The Joint IOUs have conducted three workshops (on August 28, 2019, 27

September 6, 2019, and March 18, 2020) regarding the design of the Joint 28

Study. Notice of these workshops was provided to parties on the service lists in: 29

Rulemaking (R.) 18-07-006 (Affordability Rulemaking), R.12-06-013 (Residential 30

Rate Reform), and Application (A.) 16-06-013 (PG&E GRC Phase II). 31

3 See ALJ’s Ruling in A.19-03-002, Directing SDG&E to File/Serve Addition Information,

issued November 1, 2019.

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9-3

The third and final workshop, on March 18, 2020, provided stakeholders the 1

opportunity to discuss the initial EUS Plan filed on November 22, 2019. The 2

final study plan incorporates many of the additional suggestions shared by 3

stakeholders at that workshop. The Joint IOUs expect that this final EUS plan 4

will continue evolve as Commission guidance is received and further stakeholder 5

workshops are held. 6

E. Cost-Tracking for the Electric Essential Use Study 7

Upon completion of the Study, PG&E proposes to file a Tier 2 advice letter 8

with details of the actual costs as compared to the estimated costs. With the 9

Commission’s approval of the advice letter, PG&E would then recover its portion 10

of the actual costs in distribution rates through its Annual Electric True-up advice 11

letter. 12

F. Conclusion 13

The February Ruling also ordered PG&E, on behalf of the Joint IOUs, to file 14

and serve the final EUS Plan on April 1, 2020. ALJ Doherty issued a Ruling on 15

March 30, 2020 granting the Joint IOUs’ request for seven additional business 16

days, until April 10, 2020, to file and serve the final EUS Plan. The final Joint 17

EUS Plan was filed on April 10, 2020, with parties’ concurrent Opening 18

Comments due to be filed on May 11, 2020 and concurrent Reply Comments on 19

May 26, 2020. A Proposed Decision is expected in or before July 2020. PG&E 20

requests that, as soon as possible thereafter, the Commission approve the Joint 21

IOU Study Plan (as described further in Attachment A) as well as the cost 22

recovery proposal above, as soon as possible through this expedited, bifurcated 23

separate track of this GRC Phase II proceeding. 24

(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 9

ATTACHMENT A

FINAL JOINT INVESTOR-OWNED UTILITIES’ PROPOSAL FOR

STUDY TO IDENTIFY ELECTRIC ESSENTIAL USAGE

FOR RESIDENTIAL CUSTOMERS

FINAL JOINT INVESTOR-OWNED UTILITIES’ PROPOSAL FOR

STUDY TO IDENTIFY ELECTRIC ESSENTIAL USAGE

FOR RESIDENTIAL CUSTOMERS

APRIL 10, 2020

BY PACIFIC GAS AND ELECTRIC COMPANY

ON BEHALF OF ITSELF, SOUTHERN CALIFORNIA EDISON

COMPANY AND SAN DIEGO GAS & ELECTRIC COMPANY

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-i-

FINAL JOINT INVESTOR-OWNED UTILITIES’ PROPOSAL FOR STUDY TO IDENTIFY ELECTRIC ESSENTIAL USAGE

FOR RESIDENTIAL CUSTOMERS

TABLE OF CONTENTS

A. Introduction.......................................................................................................... 1

B. How Should Essential Use Be Defined?.............................................................. 3

C. What Specific Uses Warrant Inclusion in Electric Essential Use? ....................... 8

D. What Customer Segments Should Be Included in This Study?......................... 10

1. Net Metering Status .................................................................................... 11

2. EV Owner Status ........................................................................................ 12

3. CARE/Family Electric Rate Assistance (FERA)/Non-CARE-FERAStatus.......................................................................................................... 12

4. Medical Baseline Status.............................................................................. 13

5. Other Areas of Potential EUS Variation ...................................................... 14

E. Leveraging the 2019 RASS ............................................................................... 15

F. Preliminary Budget Estimate (as of November 22, 2019).................................. 17

G. Stakeholder Engagement for Developing the Study Plan.................................. 18

H. EUS: Final Study Plan ...................................................................................... 18

1. EUS Base Deliverable................................................................................. 19

a. Project Initiation Meetings..................................................................... 19

b. Stakeholder Working Group ................................................................. 20

c. EUS Report .......................................................................................... 20

d. Custom Modeling of Energy Use Specific to Essential Usage.............. 20

e. Interactive Web Tool............................................................................. 20

f. Long-Term Maintenance of the Web Tool ............................................ 21

g. Interactive Web Tool Training Workshop.............................................. 21

h. Annotated Training Deck for Presentation Materials ............................ 22

2. Additional Task Component: Collecting Additional Data from Existing RASS Study Respondents .......................................................................... 22

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FINAL JOINT INVESTOR-OWNED UTILITIES’ PROPOSAL FOR STUDY TO IDENTIFY ELECTRIC ESSENTIAL USAGE

FOR RESIDENTIAL CUSTOMERS

TABLE OF CONTENTS(CONTINUED)

-ii-

3. Additional Task Component: Interviewing Additional RASS Study Respondents............................................................................................... 23

4. Additional Task Component: Qualitative Interviews of RASSRespondents to Gain an Understanding of Underutilization of Electricity..................................................................................................... 25

5. Additional Task Component: Added Functionality to Web Tool .................. 26

I. Timeline for Executing the Essential Use Study ................................................ 29

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-1-

FINAL JOINT INVESTOR-OWNED UTILITIES’ PROPOSAL FOR 1

STUDY TO IDENTIFY ELECTRIC ESSENTIAL USAGE2

FOR RESIDENTIAL CUSTOMERS3

A. Introduction4

Ordering Paragraph (OP) 14 of California Public Utilities Commission 5

(CPUC or Commission) Decision (D.) 18-08-013, issued August 17, 2018, 6

directed Pacific Gas and Electric Company (PG&E):7

…to develop a study plan (including budget) for developing a model of what 8constitutes essential use for its residential customers.9

The Commission issued a nearly identical requirement for Southern 10

California Edison Company (SCE) in OP 14 of D.18-11-027, issued 11

November 29, 2018. An Administrative Law Judge (ALJ) Ruling issued on 12

November 1, 2019 directed San Diego Gas & Electric Company (SDG&E) in its 13

2019 General Rate Case (GRC) Phase II Application (Application 14

(A.) 19-03-002):15

…to participate in PG&E and SCE’s stakeholder process for developing a 16model of what constitutes essential use for its residential customers, and to 17develop such a model consistent with the specific directions provided to 18PG&E in D.18-08-013.119

This ruling directed SDG&E to file and serve a document that details 20

SDG&E’s timeline for completing development of its essential use model. In the 21

summer of 2019, the three electric Investor-Owned Utilities (IOU) (collectively 22

the Joint IOUs) held two public workshops on this topic, to support the 23

development of an initial Joint IOU Essential Usage Study (EUS) Plan.224

In its November 22, 2019 GRC Phase II A.19-11-019, PG&E submitted the25

Joint IOUs’ initial EUS proposal (as Attachment A to Chapter 9), and proposed 26

that the CPUC issue a ruling expediting and bifurcating the Joint EUS from the 27

other issues in the Phase II proceeding.28

On February 10, 2020, the Assigned Commissioner and ALJ in PG&E’s 29

2020 GRC Phase II issued a Scoping Memo and Ruling (“February Ruling”) that 30

1 ALJ’s Ruling Directing SDG&E to File/Serve Supplemental Information, Issued November 1, 2019.

2 SDG&E’s response was served on November 18, 2019 in A.19-03-002.

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granted the request for a bifurcated track of this proceeding for consolidated 1

consideration of the Joint IOUs’ EUS Plan, and ordered SCE and SDG&E to file 2

for party status and participate in that portion of PG&E’s 2020 GRC Phase II. 3

The February Ruling also directed PG&E to host, on behalf of the Joint IOUs, an 4

additional public workshop on EUS design in March 2020. Accordingly, PG&E 5

served notice of the required final workshop on the appropriate service lists, 6

including: the most recent PG&E, SCE, and SDG&E3 GRC Phase II 7

proceedings, SCE’s 2019 Rate Design Window (RDW) proceeding, and the 8

CPUC’s Affordability Rulemaking (R.) proceeding, R.18-07-006. The workshop 9

was held via WebEx on March 18, 2020 (“March Public Workshop”). Finally, the 10

February Ruling ordered PG&E to serve and file the final EUS proposal on 11

behalf of the Joint IOUs on April 1, 2020. ALJ Doherty issued a Ruling on 12

March 30, 2020 granting the Joint IOUs’ request for seven additional business 13

days, until April 10, 2020, to file and serve their final EUS plan.14

This document presents the final EUS plan to identify the essential usage of 15

electricity for the Joint IOU residential customers. This final study plan 16

incorporates many of the additional comments received from stakeholders at the 17

March Public Workshop. A report on that workshop is presented herewith as 18

Attachment A2 (“March Public Workshop Report”).19

In this Final EUS plan, the Joint IOUs’ respectfully request the CPUC 20

approve their joint request to:21

1) Carry out the proposed Joint EUS as a single, coordinated statewide study, 22

to ensure consistency across the three IOUs’ respective service territories 23

and accommodate a streamlined approach to stakeholder engagement; 24

2) Contract with the 2019 Residential Appliance Saturation Survey (RASS) 25

consultant to administer the Joint EUS on a directed-award basis;26

3) Find reasonable the cost of the Base Deliverable, described in Section H27

below, of $446,103, and allow an overage cushion of 10 percent for potential 28

cost overruns, for a total potential cost of $490,714.29

4) Determine which, if any, of the additional task components described in 30

Section H below (which each carry additional costs) should also be found 31

3 SDG&E is using two service lists for its 2019 GRC Phase II proceeding: the service list for its 2016 GRC Phase II proceeding (A.15-04-012) and the service list for its 2019 Electric Sales Forecast proceeding (A.18-03-003).

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reasonable for inclusion in the final approved EUS budget, increase the 1

overall budget to allow for the additional costs and allow for an overage 2

cushion of 10 percent for each additional task components, if determined to 3

also be found reasonable for inclusion in the final approved EUS plan. At 4

this time, the IOUs also support the inclusion of two of these additional task 5

components: one to conduct qualitative interviews with 75 RASS study 6

respondents, and one to add increased functionality to the Web Tool 7

deliverable. As to the other additional task components, one to interview 8

additional RASS study respondents and one to add data from existing RASS 9

study respondents, the Joint IOUs do not currently have enough specifics to 10

support their addition at this time. However, the Joint IOUs look forward to 11

seeing the parties’ opening comments and reserve the right to modify this 12

position in our Reply Comments.13

5) Approve a cost recovery mechanism by authorizing each IOU to file a Tier 114

Advice Letter (AL) that will establish an EUS cost recovery balancing 15

account for the IOUs to begin tracking their respective share of the actual 16

costs associated with this study, and approve the Joint IOUs’ recommended 17

cost allocation of:18

PG&E, 45 percent19

SCE, 43 percent20

SDG&E, 12 percent.421

Pursuant to the February Ruling as amended by ALJ Doherty’s March 3022

Ruling adjusting the schedule, interested parties are to file and serve opening 23

comments on this final EUS proposal on May 11, 2020, and reply comments on 24

May 26, 2020.25

B. How Should Essential Use Be Defined?26

While the Scoping Memo in the Affordability Rulemaking Proceeding 27

(R.18-07-006) determined that the EUS for PG&E, and consequently for SCE, 28

should remain in their respective GRC Phase II or RDW proceedings rather than 29

4 These cost sharing ratios are consistent with the allocation of expenditures for the statewide residential rate reform marketing, education, and outreach campaign per OP 8 in D.17-12-023.

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within the scope of R.18-07-006,5 the Affordability Rulemaking has discussed 1

how essential service could be defined.2

On April 12, 2019, an ALJ Ruling (April 2019 Ruling) was issued in the 3

Affordability Rulemaking inviting comments and responses to questions 4

presented in an attachment containing background information and a summary 5

of several proposals. Attachment J to the April 2019 Ruling included the 6

following discussion regarding the definition of essential service quantity:7

Across the water and energy industries, various conceptions of an essential 8service quantity already exist. The Public Utilities Code (Pub. Util. Code) 9has provided for “an adequate supply of healthful water…at an affordable 10cost” since as early as 1993,6 and tiered rate structures common in both the 11water and energy spaces reflect the idea of an essential baseline. With that 12said, the notion of an essential service quantity can differ greatly across 13utilities, in part based on differing assumptions of what is adequate or 14reasonable. An appropriate definition for essential services should be 15flexible, applicable to all Commission-regulated utilities, and set a common 16baseline for the assumptions behind the definition. The following definition 17reflects input received from parties via comments and information from the 18January 22, 2019 workshop pertaining to this Order Instituting Rulemaking 19(OIR):20

An essential service quantity of utility service is that quantity which is 21necessary for health, comfort, and safety.7 [shading added]22

One of the questions posed in Attachment J was how this definition of 23

essential service could be refined.8 Parties to the OIR provided several 24

responses in their comments.25

On August 20, 2019, an ALJ Ruling was issued in the Affordability 26

Rulemaking inviting comments on the initial Staff Proposal on Essential Service 27

and Affordability Metrics (Initial Staff Proposal). In this proposal, Commission 28

Staff from the water, energy, and communications divisions proposed the 29

following high-level definition:30

5 See R.18-07-006, Nov. 19, 2018 Scoping Memo, p. 5.6 Pub. Util. Code § 739.8.7 R.18-07-006, Attachment J to April 2019 Ruling, p. 4.8 Id., p. 19.

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Essential Service: service that meets a household’s basic needs and is 1reasonably necessary for that household’s health, safety, and full 2participation in society.93

A public workshop concerning the Initial Staff Proposal took place on 4

August 26, 2019. Parties subsequently provided comments and reply comments 5

to the Initial Staff Proposal on September 10 and 20, 2019, respectively.6

On January 24, 2020, the CPUC issued a Revised Staff Proposal titled 7

Affordability Metrics Framework which noted that:8

…For purposes of this proposal, staff distinguishes the concepts of essential 9service and essential use or usage… Since utility use and utility service are 10dependent on a household’s specific needs, the first step in determining 11essential service for each industry is to determine what needs can 12reasonably be considered essential. From there, this proposal determines a 13specific level of essential service that must be supplied by a utility to meet 14those needs. This level may vary within and between utility service 15territories for a given industry depending on how these needs vary 16geographically. That level of essential service will correspond to an 17essential service quantity in units appropriate to the industry… Over time, 18ratepayer needs will evolve, as will the amount of utility service required, 19and staff intends for this framework to be flexible enough to accommodate 20future changes in essential service quantities.1021

Although the Revised Staff Proposal repeated the Initial Staff Proposal’s 22

suggestion that energy service is essential if it “meets a household’s basic 23

needs and is reasonably necessary for that household’s health, safety, and full 24

participation in society,” it also found that the currently- adopted baseline 25

quantities are a “reasonable estimate of essential service quantity at this 26

time.”11 The Revised Staff Proposal stated, more specifically:27

…Staff proposes that…baseline quantity definitions and methods 28established in Pub. Util. Code Section 739 be used for essential service 29quantities pending more robust determinations of these quantities by the 30large Investor-Owned Utilities (IOUs) as part of the essential use studies… 31Staff further proposes that for other energy utilities currently not required to 32participate in the essential use studies, electric and gas baseline quantities 33continue to be used for essential service quantities pending Commission 34consideration of the need for such studies.1235

9 August 20, 2019 ALJ Ruling in R.18-07-006, on initial Staff Proposal, p. 5.10 January 24, 2020 Revised Staff Report in R.18-01-006, p. 7.11 Id. p. 13.12 Id. p. 11.

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The Revised Staff Proposal further suggested that the EUS undertaken by 1

the three large electric utilities:2

…should provide more accurate determinations of essential energy service 3and eventually replace baseline quantities for that purpose. Until more 4robust determinations of essential service quantities can be made through 5essential use studies, staff considers baseline quantities the best estimate of 6essential service quantities.137

In discussing the EUS, the Revised Staff Proposal in the Affordability 8

Rulemaking noted that the Joint IOUs’ draft EUS study plan, served November 9

22, 2019 in PG&E’s 2020 GRC Phase II, calls for a coordinated statewide EUS 10

leveraging the results of the 2019 California Energy Commission (CEC) 11

Statewide Residential Appliance Saturation Study (RASS study), which was then 12

scheduled to be completed in March 2020.14 Since then, the consultant 13

performing the RASS study has indicated to the CEC that completion of the 14

study has been delayed and is currently expected to be released in Q3 2020.15

Parties to the Affordability Rulemaking have filed and served comments on 16

the Revised Staff Proposal and its proposed definitions of essential service and 17

energy essential service. A CPUC decision on the Revised Staff Proposal is 18

currently targeted for June 2020, and thus was still pending as of the date this 19

Final EUS proposal was filed.20

The Joint IOUs primarily intend to use the adopted EUS to assess whether 21

the data shows that the existing baseline quantities approach in Pub. Util. Code 22

Section 739 continues to be reasonable.15 Under the current baseline statute, 23

the CPUC sets, in each IOU’s GRC, baseline quantities for each IOU using that 24

IOU’s updated average usage data by end-use (basic or all-electric), climate 25

zone and season, multiplied by the CPUC’s selected percentage, chosen from 26

within the ranges required in the baseline statute, namely:27

50-60 percent of average usage for basic service customers in all seasons 28

and for all-electric customers in summer; or29

13 Id. p. 13.14 Id. p. 13.15 According to the CPUC’s website, a “baseline” of electricity use “is a basic amount of

power - in kilowatt hours (kWh) - that meets a significant amount of the ‘reasonable’energy needs of the average residential ratepayer.” Seehttps://www.cpuc.ca.gov/General.aspx?id=12186.

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60-70 percent of average usage for all-electric customers in the winter 1

heating season.162

Under Pub. Util Code Section 739(b): [shading added]3

The Commission shall designate a baseline quantity of gas and electricity 4which is necessary to supply a significant portion of the reasonable energy 5needs of the average residential customer. In estimating those quantities, 6the Commission shall take into account differentials in energy needs 7between customers whose residential energy needs are currently supplied 8by electricity alone or by both electricity and gas. The Commission shall 9develop a separate baseline quantity for all-electric residential customers. 10For these purposes, “all-electric residential customers” are residential 11customers having electrical service only or whose space heating is provided 12by electricity, or both. The Commission shall also take into account 13differentials in energy use by climatic zone and season.1714

Also, pursuant to Pub. Util. Code Section 739(d)(2), in establishing baseline 15

rates, the CPUC:16

…shall ensure that the rates are sufficient to enable the electrical 17corporation or gas corporation to recover a just and reasonable amount of 18revenue from residential customers as a class, while observing the principle 19that electricity and gas services are necessities, for which a low affordable 20rate is desirable and while observing the principle that conservation is 21desirable in order to maintain an affordable bill.1822

The CPUC-adopted baseline percentages have varied over time within the 23

above-stated statutory ranges, and have at times been set at the highest or the 24

lowest end of the range. It is important to remember that the current baseline 25

paradigm is enshrined in statute and is required to be based on a 26

CPUC-selected percentage of average usage within each climate zone for each 27

season, from within mandated percentage ranges set forth above. Therefore, as 28

a matter of law, if, after reviewing the parties’ post-EUS submissions, the CPUC 29

were to conclude that modification of the current ranges might be warranted, no 30

change could be implemented in rates by the CPUC until after the legislature 31

passed and the Governor signed amendments removing the current percentage 32

range approach. 33

16 See Pub. Util. Code section 739(a)(1).17 Pub. Util. Code section 739(b), emphasis added.18 Pub. Util. Code section 739(d)(2).

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C. What Specific Uses Warrant Inclusion in Electric Essential Use?1

During the course of the Affordability Rulemaking, several uses were 2

identified during consideration of a proposed definition for energy essential 3

service:4

Home heating and cooling; 5

Lighting; 6

Cooking; 7

Personal hygiene; 8

Medical care; and 9

Meaningful participation in society, such as operating a computer or 10

charging a mobile device.11

It should be noted that the 1982 Baseline Act’s “percentage range of 12

average usage” approach replaced the more “bottom-up” approach taken in the 13

legislature’s original Warren-Miller Lifeline Act of 1976. That 1976 act had14

required the CPUC to “designate a baseline quantity of gas and electricity 15

necessary to supply a significant portion of the reasonable energy needs of the 16

average residential customer at rates below average cost.19 But in the Lifeline 17

predecessor to today’s Baseline program the legislature had utilized a bottom-up18

approach based on types of usage, such as home heating and cooling, lighting, 19

and cooking, as well as listing particular medical equipment. Apparently, by 20

1982, the legislature had concluded that its original appliance-based Lifeline 21

approach had become too cumbersome, and thus opted to adopt the 22

percentage-of average usage by climate zone and season approach that has 23

been used ever since by the CPUC to determine the baseline quantities which24

are used to set the lower price applicable in the first tier in CPUC-adopted tiered 25

residential energy rates.26

In addition, when the Baseline Act was passed in 1982, the legislature also 27

required the CPUC to adopt a low-income rate discount (initially called the Low 28

Income Rate Assistance (or LIRA) program, but was later changed to the 29

California Alternate Rates for Energy (CARE) Program (see discussion of CARE 30

in Section D below). It is important to remember that when the legislature 31

19 Original 1976 text of Pub. Util. Code section 739, per Warren-Miller Energy Lifeline Act of 1976, as cited in CPUC Order Instituting Rulemaking R.12-06-012.

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adopted an average-usage percentage range-based approach to setting 1

baselines, it did so knowing that there would also be a low-income rate discount 2

to further help address affordability. Although the LIRA Program thereafter 3

adopted by the CPUC provided a 15 percent discount for low-income customers, 4

the CARE discount is much more significant, providing a 35 percent discount. 5

And the current CARE programs cover over 25 percent of each of the Joint 6

IOUs’ residential electric customers.7

For purposes of this EUS proposal, the Joint IOUs note that the RASS study 8

includes detailed questions relating to each of the above-stated usage types, as 9

well as many more usage types (including many that stakeholders have not 10

considered essential, such as swimming pools, spas, saunas, etc.; see the 11

complete RASS survey instrument, presented herewith as Attachment A2). The 12

parties to the EUS design workshops noted that there appear to be some “gray 13

areas” where it is unclear whether certain types of usage should be considered 14

to be “essential” at this time (e.g., electric vehicle (EV) charging, battery storage 15

charging, computer use and TV watching). The parties concluded that data 16

analysis was needed before a more precise definition of essential use could be 17

determined or recommended.18

Fortunately, during the EUS design workshops, the parties generally agreed 19

with the Joint IOUs that the RASS study data will provide good information to 20

provide parties the ability to perform their own refined analyses, and thereafter 21

make informed recommendations to the CPUC. Thus, this EUS proposal 22

includes, as defined in Section H below, the proposed budget for the Base 23

Deliverable using RASS study data to develop an EUS model ($490,71420).24

However, in Section H, this proposal also sets forth additional task 25

components that the Joint IOUs believe may achieve study objectives suggested 26

by various parties at the March Public Workshop -- but where no consensus was 27

reached. For each of these additional task components, Section H sets forth the 28

estimated respective additional budget [and timeline impact, where applicable], 29

to allow the CPUC the flexibility to decide to add one or more of these additional 30

20 The cost of the Base Deliverable, described in Section H below, is $446,103. A total potential cost of $490,714 for the Base Deliverable presumes that the CPUC grants the Joint IOUs’ request to provide for an overage cushion of 10 percent for potential cost overruns.

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task components, if any, after it reviews the parties’ opening and reply 1

comments. At this time, the Joint IOUs recommend approval of the Base 2

Deliverable, plus two additional task components: one to conduct qualitative 3

interviews with 75 RASS respondents, and one to add increased functionality to 4

the Web Tool deliverable. As to the other additional task components, the Joint 5

IOUs do not currently have enough specifics to support their addition at this 6

time, but look forward to seeing the parties’ opening comments and reserve the 7

right to modify this position in our Reply Comments.8

D. What Customer Segments Should Be Included in This Study?9

In D.18-08-013 and D.18-11-027, the Commission stated that the model for 10

determining essential use must be able to specify essential usage based on the 11

needs of residential customers uniquely within the following geographic areas:12

Hot climate zone – summer and winter (for PG&E, this represents Baseline 13

Territories R, S, W, and P; for SCE, this represents California Climate Zones 14

10, 13, 14, and 15, and for SDG&E, this represents Mountain and Desert 15

Climate Zones);16

Warm climate zone – summer and winter (for PG&E, this represents 17

Baseline Territories X and Y; for SCE, this represents California Climate 18

Zones 5 and 9, and for SDG&E, this represents the Inland Climate Zone); 19

and20

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Cool climate zone – summer and winter (for PG&E, this represents Baseline 1

Territories T, V, and Z; for SCE, this represents California Climate Zones 6,2

8, and 16, and for SDG&E, this represents the Coastal Climate Zone).213

During the March Public Workshop, the IOUs received further information 4

from the stakeholders for follow-up data collection on specific customer 5

segments, and discussed whether this data segmentation is already possible 6

using the RASS data. The additional task components represent the Joint IOUs’ 7

best understanding of areas that some subset of parties indicated they might like 8

the CPUC to consider adding to the Base Deliverable, followed by the Joint 9

IOU’s current recommendation as to each:10

1. Net Metering Status11

The RASS study, by virtue of data appended by IOU records, already 12

includes customer information on whether each customer in the RASS study 13

group is on a Net Energy Metering (NEM) rate rider or not. The Public 14

Advocates Office at the California Public Utilities Commission 15

(Cal Advocates) suggests that for net metering, EV, and all-electric 16

customers, there should be a filter in the proposed EUS web-based tool to 17

allow these customers to be analyzed separately from the basic essential 18

use analysis, due to their less common usage needs.22 The Joint IOUs 19

21 The Center for Alternative Technologies (CforAT) suggested, during the public EUS workshops, that weather variations within climate zones—typically referred to as microclimates—might affect the amounts of electricity required for essential uses and requests that these differences be assessed in the EUS. The RASS study builds from billing data and designations from the IOUs’ billing systems, which includes information about the specific location of each customer in the RASS sample, thus allowing analysis at a more granular basis than just by existing climate zones. However, PG&E would note that in the later portion of its GRC Phase II proceeding, the CPUC will consider its November 22, 2019 compliance study analyzing three scenarios for potential modification to the current climate zone designations, and its recommendation that neither a reduction to three climate zones (hot, warm and cool), nor use of Zip codes (which are determined by the U.S. Postal Service without reference to climate data and the boundaries for which are periodically changed by the USPS, which would raise significant billing system reprogramming issues) is appropriate. Thus, PG&E has concluded that it is premature at this time for the CPUC to make any changes to PG&E’s existing climate zones based on the analysis in that compliance study. (See PG&E’s testimony provided in support of its November 22, 2019 2020 GRC Phase II (A.19-11-019)).

22 The Public Advocates Office at the California Public Utilities Commission: Essential Use Study Plan Questions and Suggestions, Attachment to the PG&E Essential Energy Use Workshop Notes.

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agree that there should be the ability to analyze these groups separately. 1

Such analysis is possible using the existing RASS data as to each such 2

subgroup of customers, and the basic model will allow these smaller subsets 3

of customers’ usage to be segregated from that basic essential usage 4

analysis derived from uses that are more universal. It should be noted that 5

some customers may have a combination of such added uses (e.g., both6

NEM solar, and EV usage), adding to the complexity of any determination of 7

if or how data on these subsets’ different levels of usage due to such special 8

circumstances might warrant some sort of potential addition to the basic 9

baseline quantity at some time in the future.10

2. EV Owner Status11

The RASS study already includes numerous questions on EV ownership 12

and usage patterns, and customer rate information is appended to RASS 13

respondent data through IOU billing records. However, if there is a desire to14

potentially include all or a portion of EV usage as “essential,” such as by 15

creating a separate higher baseline quantity for EV users, the RASS study 16

sample group might need to be expanded to include additional participants. 17

However, the Joint IOUs would note that, currently residential EV rate18

schedules do not generally include tiers (i.e., lower prices for baseline 19

usage). Further, EV adoption is not widespread at this time. Moreover, EV 20

owners frequently charge their vehicles at other locations (workplace, mall, 21

school or college, etc.), so this makes EV home energy use difficult to 22

estimate in studies such as RASS, that address multiple end-uses23

simultaneously. Finally, this would bring additional complexities, such as 24

how to treat households with more than one EV. For reasons such as 25

these, the Joint IOUs do not believe the additional cost and time required to 26

add EVs to essential use is warranted at this time, but rather recommend 27

that the initial EUS focus on essential use categories that are more 28

universal, and reconsider EV usage when EV penetration becomes more29

widespread.30

3. CARE/Family Electric Rate Assistance (FERA)/Non-CARE-FERA Status31

The RASS study, by virtue of data appended by IOU records, will be 32

able to add information on whether each customer in the sample was 33

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enrolled on either the CARE or FERA low-income rate discount programs. 1

Currently CARE customers receive an average effective discount of 2

approximately 35 percent and FERA customers receive an average effective 3

discount of 18 percent. CforAT suggested that more follow-up data, such as 4

qualitative research, could be helpful to determine whether low-income 5

households might be underutilizing energy due to financial pressures or 6

other causes. Billing information can be appended to the RASS study data 7

to indicate whether each customer in the study group is enrolled in the 8

CARE and FERA programs or not, thus allowing quantitative analysis of the 9

association of electricity use, self-reported household income, and customer 10

enrollment in these programs. The additional task component of qualitative 11

interviews with 75 RASS study respondents could provide additional insight 12

into customers enrolled in the CARE and FERA programs that might still be 13

underutilizing energy due to financial constraints.14

For this reason the Joint IOUs support inclusion of this additional task 15

component into the EUS to seek further insight into CforAT’s underutilization 16

hypothesis. However, by supporting the inclusion of this task component 17

(see Section H below), the Joint IOUs are not prejudging whether any such 18

analysis might be significant enough to warrant modification to the current 19

baseline statute’s percentage range approach.20

4. Medical Baseline Status21

The RASS study, by virtue of data appended by IOU records, will be 22

able to add information on whether each customer in the sample was 23

participating in the medical baseline program. Currently, the IOUs provide 24

additional daily baseline allowances to eligible customers on tiered rates 25

above the standard baseline quantity.23 The draft EUS plan proposed to 26

use existing demographic data to cross-reference customer types to get a 27

better sense of energy usage by medical baseline customers. However, at 28

the March 18, 2020 workshop, DNV GL observed that customers enrolled in 29

23 PG&E’s medical baseline program provides eligible customers with an initial Medical Baseline adder of 500 kilowatt-hours (kWh) per month, with a potential additional increment of 500 kWh for those with even greater needs. At SDG&E, customers eligible for medical baseline receive an additional daily baseline allowance of 16.5 kWh per day and an additional allowance if allowed in exceptional circumstances.

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the medical baseline program represent a small part of the RASS 1

respondent population. CforAT suggested that the EUS could survey 2

customers regarding their use of specific types of medical equipment to gain 3

a better understanding of the relationship between the usage of medical 4

equipment, potential under-enrollment in the medical baseline program, and 5

underutilization of electricity. DNV GL observed that usage of medical 6

equipment is not the best indicator of health-related energy needs.24 The7

additional task component of adding data from existing RASS study 8

respondents, detailed in Section H, could explore the medically-related 9

issues of essential usage of electricity in greater detail. Given the high costs 10

associated with this additional task component (see Section H), the Joint 11

IOUs do not currently support its inclusion into the EUS. However, the Joint 12

IOUs look forward to seeing the parties’ opening comments and reserve the 13

right to modify this position in our Reply Comments.14

5. Other Areas of Potential EUS Variation15

While the existing RASS survey already included questions on the 16

number and time spent using personal computers and other electronic 17

devices, some or all of which ultimately might be found to be part of what 18

should be considered “essential usage,” it is possible that additional 19

questions from RASS study respondents might help shed light on whether 20

some portions or all of such usage might be considered to be21

“non-essential” (such as computer use for instructional or business use, or 22

for streaming of certain video content). Based on the discussions at the 23

workshop, the Joint IOUs have provided costs for the additional task 24

component of collecting data from existing RASS study respondents that 25

could be leveraged to help learn more about certain electric use types where 26

energy use may vary, such as for computers (e.g., seeking to remove usage 27

for streaming and video gaming), as detailed in Section H below. Given the 28

substantial cost of the additional task component, the Joint IOUs do not 29

support this additional task component to the Basic Deliverable until other 30

stakeholders file their opening comments and include more specifics on the 31

nature of the additional questions they are seeking to add. The Joint IOUs 32

24 March Public Workshop Report, pp. 4-5.

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are open to informally continuing discussions with any stakeholder who 1

wishes to provide further guidance about the type of questions that might be 2

included as part of this additional task component.3

E. Leveraging the 2019 RASS4

In both D.18-08-013 and D.18-11-027, the Commission recognizes the 5

critical role that the 2019 RASS would play in the development of an EUS. 6

OP 14 of D.18-08-013 states that the EUS7

…must be developed using research, both existing (information sources 8such as the Residential Appliance Saturation Survey and Experian data) 9and new direct customer surveys, to collect information on household size 10(in terms of both square footage and number of residents), building features 11(age, construction materials, insulation, etc.), and appliances (efficiency and 12usage) in order to better evaluate the essential electricity needs of PG&E’s 13residential customers.2514

The 2019 RASS is a large-scale, statewide study that has been conducted 15

periodically over the past few decades to estimate the saturation of typical 16

residential appliances and energy consumption tied to a wide range of common 17

end uses of energy. Utilities participating in the 2019 RASS include Los Angeles 18

Department of Water and Power, PG&E, SCE, SDG&E, Southern California Gas 19

Company, and the Sacramento Municipal Utilities District. Using both mail—and20

e-mail based respondent recruitment techniques, the targeted completed sample 21

size for the 2019 RASS is approximately 51,500 California households, 22

over 45,000 of were to be in Joint IOU service territories and is the most 23

comprehensive survey of California residents of its kind. As of this filing, the 24

Joint IOUs have learned that these overall targets are unlikely to be achieved in 25

the time remaining of the survey implementation phase. For this reason, 26

Section H provides for two options to attempt to boost the RASS sample size in 27

specific lower-income segments of the IOU populations to increase its 28

25 D.18-08-013, p. 179. Comparable language can also be found in OP 14 of D.18-11-027for SCE’s essential use study:

The SCE study plan must consider a model that uses research, both existing (information sources such as the Residential Appliance Saturation Survey and Experian data) and new direct customer surveys, to collect information on household size (in terms of both square footage and number of residents), building features (age, construction materials, insulation, etc.), and appliances (efficiency and usage) in order to better evaluate the essential electricity needs of SCE’s residential customers.

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usefulness as the base for the EUS. The Joint IOUs support the addition of 1

additional surveying of targeted populations as outlined in Section H below.2

The 2019 RASS will estimate unit energy consumption of specific end uses 3

of electricity using a Conditional Demand Analysis (CDA), which has been 4

refined over the past 30 years. CDA combines meter data from utilities, survey 5

data on appliances in homes and household demographics, temperature data, 6

and engineering models to estimate average energy usage for specific 7

appliances or end-uses. Household members are surveyed to obtain 8

demographic information, end-use appliances and equipment in the dwelling, 9

and occupant usage habits. This information is combined with end use 10

engineering estimates to create a bottom-up estimate of each household’s 11

energy consumption profile. The results of the statistically—adjusted end use 12

usage estimates, aggregated over the sample population, produce the 13

segment—and population—level end use average usage estimates. The 2019 14

RASS is expected to be completed by autumn, 2020.15

The Commission in D.18-08-013 and D.18-11-027 determined that, to better 16

evaluate the essential electricity needs of residential customers, the model for 17

determining essential use must collect information on the geographic segments 18

listed in Section D above and on the following customer attributes:19

Household size (in terms of both square footage and number of residents);20

Building features (age, construction materials, insulation, etc.); and21

Appliances (efficiency and usage).22

These requirements are met with the 2019 RASS questionnaire.26 The 23

mail-based 2019 RASS survey instrument is provided as Attachment A2 to this 24

document. Table 4 provides cross-references between the 2019 RASS 25

questions and household size and building features. Table 5 provides 26

cross-references between the 2019 RASS questions and appliances.27

Further, the IOU proposal calls to build upon the 2019 RASS by using its 28

respondent pool to fill in any gaps in the existing questionnaire and as the 29

26 The RASS questionnaire did not ask respondents about dwelling construction materials.

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source for new survey respondents for follow-on surveys27 when practical. 1

One factor to weigh in the decision whether to re-contact the RASS participants 2

is the cost to do so. This cost is discussed in the budget estimate that follows in 3

Section H.4

F. Preliminary Budget Estimate (as of November 22, 2019)5

In the November 22, 2019 Joint IOU draft EUS plan, the IOUs provided the 6

following information on the preliminary budget estimate related to the IOUs’ 7

initial study plan proposal.8

The CEC used a competitive solicitation process to award the administration 9

of the 2019 RASS Study (initially referred to by the CEC as the “2017 RASS” 10

due to a delay in issuing the contract) to the consultant DNV GL (doing business 11

as KEMA, Inc.) based on this firm’s experience in conducting prior versions of 12

the RASS study and on the knowledge and skills of the firm’s staff in conducting 13

in-depth analyses of household energy consumption patterns. Based in part on 14

DNV GL’s deep expertise with administering RASS studies, and prior IOU 15

experience contracting with DNV GL on other research projects, the IOUs intend 16

to issue a direct award for the preliminary design of the EUS to this consultant, 17

provided that the Commission has no objections.28 In doing so, the survey 18

design, data collection, and conditional demand estimates performed for the 19

RASS can be leveraged to expedite implementation, reduce the costs of 20

producing the EUS, and ensure the quality of essential energy use estimates.21

Based on this proposal and prior studies of similar scope and magnitude, 22

the consultant, DNV GL, had provided a preliminary cost estimate range for the 23

27 During the March 18, 2020 workshop, the Cal Advocates requested that all new data collected for the electric EUS be open for inspection by the stakeholders so that it can be validated, can provide for continued engagement, and its interpretation can include multiple perspectives.

28 During the public meeting, The Utility Reform Network (TURN) questioned how a direct award of a contract to DNV GL to conduct the study would benefit stakeholders. The IOUs explained that DNV GL analysts have demonstrated expertise in demand modeling and have knowledge of both the data structure of 2019 RASS and the content of the surveys. Further, the IOUs explained that contracting with a different vendor without access to the RASS data would result in the new vendor having to begin anew and ratepayers being required to pay more to execute the EUS. After discussion, Cal Advocates and TURN had no major objections to the hiring of DNV GL or to the Joint IOU effort, provided that stakeholders are given information about the scope, scale and cost of the project prior to the awarding of any contracts.

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November 20, 2020 EUS proposal of between $550,000 and $750,000. It was 1

noted that the final cost of the EUS would be dependent on the extent of 2

stakeholder collaboration, the characteristics of the final study design and the 3

timetable of its execution.4

G. Stakeholder Engagement for Developing the Study Plan5

OP 14 of D.18-08-013 and OP 14 of D.18-11-027, required that PG&E and 6

SCE, respectively, “consult with parties to this proceeding,…when developing 7

this study plan,”29 referencing both PG&E and SCE’s GRC Phase II 8

proceedings. For SDG&E, the ALJ Ruling issued November 1, 2019 directed 9

SDG&E:10

…to participate in PG&E and SCE’s stakeholder process for developing a 11model of what constitutes essential use for its residential customers, and to 12develop such a model consistent with the specific directions provided to 13PG&E in D.18-08-013.3014

The IOUs conducted two public meetings, one on August 28, 2019 and 15

another on September 6, 2019, both of which included the noticing of parties to 16

R.18-07-006 and the parties to PG&E and SCE’s GRC Phase II proceedings, to 17

inform the development of the draft EUS plan. Parties were also invited to 18

provide comments directly to the study plan through an online document. The 19

draft Joint IOU EUS plan proposal provided on November 22, 2019 reflected 20

comments received from stakeholders as of Fall 2019, with the IOUs indicating 21

they intended to continue collaboration efforts with stakeholders in the 22

development a final EUS plan.23

The February 2020 Assigned Commissioner’s Ruling directed PG&E to host 24

an additional public workshop on EUS design in March of 2020 (the March 25

Public Workshop). A report on that workshop is included as Attachment A1.26

H. EUS: Final Study Plan27

The final EUS Plan provides for a Base Deliverable, details of which are 28

provided below, that addresses the fundamental requirements for developing a 29

model of what constitutes essential use by residential customers of the Joint 30

29 OP 14 of D.18-08-013, p. 179; OP 14 of D.18-11-027, p. 76.30 ALJ Ruling, dated November 12, 2019, A.1903-002, p. 2. SDG&E’s response was

served on November 18, 2019.

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IOUs, as directed by the Commission.31 Stakeholders that participated in the 1

March Public Workshop provided feedback on the November 22, 2019 EUS plan 2

and discussed whether additional data collection beyond that available in the 3

2019 RASS Study was desired, as well as potential deliverables. The 4

discussions at the March Public Workshop are summarized in a document 5

entitled “PG&E Essential Energy Public Workshop Notes,” incorporated in this 6

filing as Attachment A1. The key stakeholder suggestions for modifications to 7

the draft EUS plan are incorporated into this final EUS plan as “Additional Task 8

Components” to the Base Deliverable. Each of these Additional Task 9

Components are optional deliverables that may enhance the Base Deliverable 10

and address stakeholder suggestions made at the March Public Workshop. The 11

Additional Task Components do not replace the Base Deliverable. Each of 12

these components is independent of the others, and each has its own costs, as 13

explained below.14

1. EUS Base Deliverable15

The final EUS plan is to deliver a “Base Deliverable” as the foundational 16

deliverable. The estimated timeframe for completion of the EUS Base 17

Deliverable is four months after the formal direct-award of the contract by 18

PG&E to DNV GL at an estimated cost of $490,714. This cost estimate 19

provides for the estimated cost of $446,103, plus a 10 percent overage20

cushion of $44,610. The cost estimate presumes that the CPUC grants the 21

Joint IOUs’ request to provide for an overage cushion of 10 percent for 22

potential cost overruns. The EUS Base Deliverable consists of the following 23

elements.24

a. Project Initiation Meetings25

The EUS will begin with two project initiation meetings, one with the 26

IOU study team, and one that will include interested stakeholders. The 27

objective of the stakeholder meeting is to confirm the project timeline, 28

and the scope of the key deliverables. The stakeholder meeting will be 29

31 See OP 14 of D.18-08-013, issued August 17, 2018; OP 14 of D.18-11-027, issued November 29, 2018; and ALJ Ruling directing SDG&E to File/Serve Supplemental Information, issued November 1, 2019.

(PG&E-3)

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moderated by a third party, and the outcome of this meeting will be 1

documented in notes that will made available to all meeting participants.2

b. Stakeholder Working Group3

The EUS will include a working group comprised of interested 4

stakeholders that will meet periodically, at a cadence to be agreed upon 5

by consensus, but no less than monthly, throughout the study. 6

Discussions and decisions resulting from the working group meetings 7

will be documented in notes that will be made available to all working 8

group participants.9

c. EUS Report10

The EUS Report will summarize the study methodology; caveats 11

and limitations for its use; key findings including estimates of typical end 12

uses commonly associated with essential uses of electricity in kWh, with 13

comparisons to currently-established baseline quantities in hot, warm, 14

and cool climate areas; how the data can support investigation of the15

essential use of electricity; and a summary of the study’s outcomes, 16

including relevant trends.17

d. Custom Modeling of Energy Use Specific to Essential Usage18

Since central air conditioning may be considered as an essential 19

use of electricity when outdoor temperatures exceed a certain threshold, 20

conditionally determined to be 82 degrees Fahrenheit, the EUS will 21

include custom modeling of interval data to estimate the energy use 22

associated with cooling at higher temperatures; and estimation of the 23

proportion of customers at home not utilizing central air conditioning until 24

a temperature threshold is reached before they start cooling their homes 25

(as a possible indicator of electricity underutilization). A similar process 26

will be repeated for heating: a threshold outdoor temperature will be 27

selected, and energy use at or below that outdoor temperature will be 28

modeled to estimate essential use and underutilization.29

e. Interactive Web Tool30

The EUS will include an online public tool that will provide a set of 31

downloadable tables that will provide estimates of the end uses of 32

electricity, in a cross-tabular format. Stakeholders will be provided the 33

(PG&E-3)

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opportunity to help define the content of these tables during the project 1

initiation meeting.2

In addition to these downloadable tables, the web tool will provide a 3

capability to create queries using the 2019 RASS data underpinning the 4

kWh estimates for end uses of electricity created using the CDA 5

methodology. To extend the applicability of the 2019 RASS database 6

for the analysis of the essential uses of electricity, additional custom 7

quantitative analyses of the existing RASS database will be undertaken. 8

These customizations, to be determined jointly by stakeholders and 9

DNV GL at the stakeholder project initiation meeting, may include, but 10

are not limited to: identification of customers to include and/or exclude 11

for the purposes of estimate development; new weights development; 12

estimation of energy expenses under different scenarios; incorporation 13

of data from other sources, and inclusion of medical baseline and/or 14

medical-related electricity usage data.15

So that this web tool can leverage the functionality of the 2019 16

RASS web tool, the EUS Web Tool will not be available until after the 17

2019 RASS data tool has been launched and fully debugged. It is 18

anticipated that the 2019 RASS project will be completed prior to the 19

EUS, so that this dependency will not impede the delivery of the EUS 20

Web Tool of the study deliverable.21

f. Long-Term Maintenance of the Web Tool22

The contractor will maintain the Web Tool to assure that it is 23

operational for a period of a minimum of seven years after the 24

completion of the Interactive Web Tool Training Workshop deliverable 25

(described below).26

g. Interactive Web Tool Training Workshop27

The EUS will include a three and one-half hours public workshop to 28

demonstrate the EUS web tool to interested parties. Stakeholders will 29

have the ability to contact the web tool developers after the workshop for 30

follow-on questions, should they arise.31

(PG&E-3)

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h. Annotated Training Deck for Presentation Materials1

The EUS will include a training presentation-style manual that will 2

accompany the web tool that will document how the tool was put 3

together and could be used, along with instructions on how to use the 4

tool for the use of new, future users.5

2. Additional Task Component: Collecting Additional Data from Existing 6

RASS Study Respondents7

In the March Public Workshop, various stakeholders suggested 8

analyses on essential use that could benefit from collecting more information 9

from RASS respondents. The rationale for this approach is that obtaining 10

more detail on particular responses from a subset of RASS respondents 11

would provide the opportunity to gain a more nuanced understanding of one 12

or more subject areas related to essential use that are not covered in 13

sufficient detail in the questions in the RASS survey instrument. To provide 14

for the opportunity to collect greater detail on particular responses provided 15

to the RASS survey, this additional task component is offered as an option 16

for inclusion to the EUS plan.17

The Joint IOUs do not currently have enough specifics to support the 18

addition of this additional task component at this time. However, the Joint 19

IOUs look forward to seeing the parties’ opening comments regarding how 20

this additional task component might provide benefit to the EUS and reserve 21

the right to modify this position in our Reply Comments.22

In this additional task component, one or more subsets of RASS survey 23

respondents will be targeted for additional interviews that will be comprised 24

of up to 10 additional questions, to be agreed upon in collaboration with 25

stakeholders. Responses will be integrated with the RASS dataset and 26

incorporated into the Base Deliverable components described above 27

(e.g., into the interactive web tool and the study report). The interviews will 28

be conducted by a sub-contractor to DNV GL, Apprise, Inc., a recognized 29

company that specializes in surveying hard-to-reach residential 30

respondents. Staff members of Apprise, Inc. will use both online and 31

telephone survey modalities to reach RASS respondents. To maximize 32

response rates, incentives will be provided and all potential respondents will 33

be contacted multiple times. The final number of completed surveys cannot 34

(PG&E-3)

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be guaranteed. Since stakeholders participating in the March Public 1

Workshop expressed a desire to be able to make estimates of essential use 2

for different end uses of electricity for specific customer groups, costs for 3

two target sample sizes are provided to inform the decision regarding the 4

costs and benefits of including this additional task component. Although a 5

larger set of interviews will provide greater statistical power to analyze the 6

responses for unique configurations of customer groups of interests, the 7

costs for data collection are higher.8

2a. 2,000 interviews targeted with existing RASS study respondents. 9

Estimated response rate is 50 percent with a total estimated number of 10

completed interviews of 1,000. The cost estimate is $108,575. This 11

cost estimate provides for the estimated cost of $98,704, plus an 12

overage cushion of $9,870, which represents 10 percent of the cost 13

estimate, and includes the cost of respondent incentives. The cost 14

estimate presumes that the CPUC grants the Joint IOUs’ request to 15

provide for an overage cushion of 10 percent for potential cost overruns.16

2b. 6,000 interviews targeted with existing RASS study respondents. 17

Estimated response rate is 50 percent with a total estimated number of 18

completed interviews of 3,000. The cost estimate is $211,579. This19

cost estimate provides for the estimated cost of $191,545, plus an 20

overage cushion of $19,155, which represents 10 percent of the cost 21

estimate, and includes the cost of respondent incentives. The cost 22

estimate presumes that the CPUC grants the Joint IOUs’ request to 23

provide for an overage cushion of 10 percent for potential cost overruns.24

3. Additional Task Component: Interviewing Additional RASS Study 25

Respondents26

Several comments made during the March Public Workshop suggested 27

that stakeholders see the value of the Web Tool deliverable is directly 28

related to the level of detail available for specific customer segments of 29

interest. For example, TURN said that users should be able to download 30

collected data in their own spreadsheets for analysis.32 Also, in its follow-up31

questions to the March Public Workshop, Cal Advocates questioned 32

32 March Public Workshop Report, p. 7.

(PG&E-3)

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whether the existing RASS study sample size is adequate to produce 1

estimates of essential usage for customers by utility baseline territory.332

The Joint IOUs agreed that the number of RASS study respondents—3

particularly specific lower-income segments—could influence the extent to 4

which the Web Tool could generate statistically reliable estimates of electric 5

use for specific end uses. To provide for an increase in statistical precision 6

for estimates generated by the Web Tool, this additional task component is 7

offered as an option for inclusion to the EUS plan. The Joint IOUs do not 8

currently have enough specifics to support the addition of this additional task 9

component at this time. However, the Joint IOUs look forward to seeing the 10

parties’ opening comments regarding how this additional task component 11

might provide benefit to the EUS and reserve the right to modify this position 12

in our Reply Comments.13

This option provides for the targeting of specific subset(s) of the 14

lower-income IOU populations that were targeted for the 2019 RASS study, 15

but for which a greater number of completed interviews would provide 16

benefit to the Web Tool for making estimates of end-uses of electricity. The 17

potential interviews will be conducted by a sub-contractor to DNV GL, 18

Apprise, Inc., that specializes in surveying hard-to-reach residential 19

respondents. Interviews will be attempted both by online and telephone, 20

and incentives will be provided. All potential new RASS study respondents 21

will be attempted to be contacted multiple times, but the final number of 22

completed surveys cannot be guaranteed. This option provides for two 23

alternative targeted sample sizes, to balance benefits and costs. Cost 24

estimates for each option are provided below.25

3a. Additional 6,000 new RASS study respondents targeted. Estimated 26

response rate is 30 percent, with a total estimated number of completed 27

interviews of 2,000. Cost estimate is $286,000. This cost estimate 28

provides for the estimated cost of $251,000, plus an overage cushion of 29

$35,000, which represents 10 percent of the cost estimate, and includes 30

the cost of respondent incentives, plus an additional 25 percent of the 31

cost estimate for printing and shipping of the surveys, due to 32

33 March Public Workshop Report, p. 9.

(PG&E-3)

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uncertainties surrounding these costs as a result of the pandemic. The1

cost estimate presumes that the CPUC grants the Joint IOUs’ request to 2

provide for an overage cushion of 10 percent for potential cost overruns 3

for the additional task component activities, except for an overage 4

cushion of 25 percent for the printing and shipping costs of the 5

surveys only.6

3b. Additional 12,000 new RASS study respondents targeted. Estimated 7

response rate is between 30 percent, with a total estimated number of 8

completed interviews between 4,000. Cost estimate is $458,000. This 9

cost estimate provides for the estimated cost of $400,000, plus an 10

overage cushion of $58,000, which represents 10 percent of the cost 11

estimate, and includes the cost of respondent incentives, plus an 12

additional 25 percent of the cost estimate for printing and shipping of the 13

surveys, due to uncertainties surrounding these costs as a result of the 14

pandemic. The cost estimate presumes that the CPUC grants the Joint 15

IOUs’ request to provide for an overage cushion of 10 percent for 16

potential cost overruns for the additional task component activities,17

except for an overage cushion of 25 percent for the printing and 18

shipping costs of the surveys only. The cost estimate presumes that the 19

CPUC grants the Joint IOUs’ request to provide for an overage cushion 20

of 10 percent for potential cost overruns.21

4. Additional Task Component: Qualitative Interviews of RASS 22

Respondents to Gain an Understanding of Underutilization of 23

Electricity24

At the March Public Workshop, stakeholders suggested that the IOUs 25

consider how the EUS can incorporate qualitative data, to supplement the 26

quantitative data collection from the RASS study, to help identify energy 27

underutilization by low-income customers, either through follow-up surveys 28

or through comparative analysis with other datasets.34 So that stakeholders 29

can gain a nuanced understanding of the extent to which low income 30

customers might be under-utilizing electricity due to its cost, the Joint IOUs 31

propose the additional task component of in-depth interviews with RASS 32

34 March Public Workshop Report, p. 2.

(PG&E-3)

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study respondents. The Joint IOUs support the inclusion of this additional 1

task component. 2

This additional task component provides for a minimum of 75 interviews 3

to be completed with existing 2019 RASS respondents across the 4

three Joint IOU territories with customers in different age groups and of 5

different sexes, so as to gain many customer perspectives. Included in this 6

deliverable is the development of the survey instrument35 and its 7

pre-testing, conducting the respondent interviews, their interpretation, and 8

inclusion of the results into the summary report. The cost for this option 9

is $85,524. This cost estimate provides for the estimated cost of $77,749,10

plus an overage cushion of $7,749, which represents 10 percent of the cost 11

estimate, and includes the cost of respondent incentives. The cost estimate 12

presumes that the CPUC grants the Joint IOUs’ request to provide for an 13

overage cushion of 10 percent for potential cost overruns.14

5. Additional Task Component: Added Functionality to Web Tool15

Stakeholders at the March Public Workshop expressed that the Web 16

Tool would be of greater utility than a study report. For example, TURN said 17

that they wish to construct their own interpretations of the dataset36 and18

Cal Advocates presented a number of questions after the March Public 19

Workshop regarding the types of estimates that the Web Tool would be able 20

to produce.37 To address these requests, this additional task component 21

provides for the development of additional statistical estimate functionality, 22

including calculation of confidence intervals and/or other estimates of 23

accuracy, to be designed and integrated into the EUS Web Tool. DNV GL24

statistical subject matter experts (SME) will be heavily engaged in the 25

design of these enhanced statistical capabilities, and stakeholders will be 26

provided opportunity to provide input into the identification and specification 27

of these enhancements during the project initiation meeting.28

35 Stakeholders suggested that the Low Income Needs Assessment and survey questions from the study conducted under Pub. Util. Code Section 745 can provide guidance on questions to identify underutilization.

36 March Public Workshop Report, p. 8.37 March Public Workshop Report, p. 9.

(PG&E-3)

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The cost for this option is $40,000, or $60,000 if integration of additional 1

questions from additional task component 2a or 2b is included. These costs 2

provide for the estimated costs of $36,000 and $54,000, respectively, plus 3

overage cushions of $3,656 and $5,440, respectively, which represent 4

10 percent of the costs. The costs presume that the CPUC grants the Joint 5

IOUs’ request to provide for an overage cushion of 10 percent for potential 6

cost overruns.7

(PG&E-3)

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TABLE 1COST ESTIMATES FOR FINAL ESSENTIAL USE STUDY

LineNo. Study Option Cost Estimate

Joint IOUs’ Position

1 Base Deliverable of the Essential Use Study based on 2019 RASS data only, without additional data collection, including creation of model and Web Tool to allow parties to perform their own analyses using this data, and all other deliverables as listed in the Base Deliverable Section presented in Section H above.

$490,714(includes $44,610,which represents a cost-overrun cushion of 10 percent(a))

Support

2a Additional Task Component: Collecting Additional Data from Existing RASS Study Respondents with up to 10 additional responses to be appended to a target of 2,000 RASS respondents. Includes mail-based outreach with incentives and intensive follow-upto maximize response rates (estimated to be 50 percent).

$108,575(includes $9,870,which represents a cost-overrun cushion of 10 percent(a))

Cannot support at this time—need further specifics from stakeholders to define and assess whether the added cost might be warranted.

2b Additional Task Component: Collecting Additional Data from Existing RASS Study Respondents with up to 10 additional responses to be appended to a target of 6,000 RASS respondents. Includes mail-based outreach with incentives and intensive follow-upto maximize response rates (estimated to be 50 percent).

$211,799(includes $19,254,which represents a cost-overrun cushion of 10 percent(a))

Cannot support at this time—need further specifics from stakeholders to define and assess whether the added cost might be warranted.

3a Additional Task Component: Interviewing Additional RASS Study Respondents with a target of an additional 6,000 completed RASS surveys in specific sub-segments of interest. Includes the addition of up to 10 questions not contained in the original RASS study survey instrument and intensive follow-up to maximize response rates (estimated to be 30 percent).

$286,000(includes $35,000,which represents a cost-overrun cushion of 10 percent(a) forlabor and a cost-overrun cushion of 25 percent(b) forprinting and shipping)

Cannot support at this time—needfurther specifics from stakeholders to define and assess whether the added cost might be warranted.

3b Additional Task Component: Interviewing Additional RASS Study Respondents with a target of an additional 12,000 completed RASS surveys in specific sub-segments of interest. Includes the addition of up to 10 questions not contained in the original RASS study survey instrument and intensive follow-up to maximize response rates (estimated to be 30 percent).

$458,000(includes $58,000,which represents a cost-overrun cushion of 10 percent(a) forlabor and a cost-overrun cushion of 25 percent(b) forprinting and shipping)

Cannot support at this time—need further specifics from stakeholders to define and assess whether the added cost might be warranted.

(PG&E-3)

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TABLE 1COST ESTIMATES FOR FINAL ESSENTIAL USE STUDY

(CONTINUED)

LineNo. Study Option Cost Estimate

Joint IOUs’ Position

4 Additional Task Component: Interviews of RASS Study Respondents to Gain an Understanding of Underutilization of Electricity with a minimum of 75 in-depth interviews to be completed with 2019 RASS respondents across the three Joint IOU territories with customers in different age groupsand of different sexes. Include development and pre-testing of the interview guide, conducting and interpreting the interviews, and including the results into the EUS report.

$85,524(includes $7,775,which represents a cost-overrun cushion of 10 percent(a))

Support

5 Additional Task Component: AddedFunctionality to Web Tool. The specific features and capabilities of this deliverable, to be designed and integrated into the EUS Web Tool, will include calculation of confidence intervals and/or other estimates of accuracy. DNV GL statistical SMEs will be heavily engaged in the design of these enhanced statistical capabilities, and stakeholders will be provided opportunity to provide input into the identification and specification of these enhancements during the project initiation meeting.

$40,000 for existing RASS study dataset$60,000 if integration of additional questions from additional task component 2a or 2b is performed (estimates include $3,565 and $5,440,respectively, which represent cost-overrun cushions of 10 percent(a) for each of the two options described above)

Support

_______________

(a) Costs shown presume that the CPUC grants the Joint IOUs’ request to provide for an overage cushion of 10 percent for potential cost overruns. Costs without the overage cushion are provided in Section H.

(b) Printing and shipping costs cannot be accurately estimated at this time due to the pandemic.

I. Timeline for Executing the Essential Use Study1

The initial Joint IOU EUS proposal was submitted with PG&E’s 2

November 22, 2019 GRC Phase II application (with the identical proposed plan 3

also being presented in SCE’s 2019 RDW application, and in SDG&E’s GRC 4

Phase II proceeding). The CPUC has since bifurcated and expedited joint 5

consideration of the EUS plan, separately from the rest of the issues within 6

PG&E’s 2020 GRC Phase II proceeding and ordered SCE and SDG&E to 7

participate in this bifurcated EUS phase of PG&E’s GRC Phase II proceeding. 8

That ruling called for the Final EUS Plan to be developed and finalized jointly, for 9

(PG&E-3)

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consideration and consolidated approval in a single proceeding, to ensure the 1

EUS is consistent across all IOUs and moves forward quickly, efficiently and at 2

the least cost possible. The schedule provided in PG&E’s November 22, 2019 3

EUS testimony had included a proposed schedule that has been amended4

below to reflect refinements based on both the February 2020 Ruling and 5

March Public Workshop discussions. Given that the Final EUS Plan was not 6

filed and served until April 10, 2020, with concomitant delays in the opening and 7

reply comment deadlines, it is assumed that the originally-envisioned target date8

of June 2020 for the Proposed Decision should be moved to July 2020, with the 9

target for a final CPUC decision on the PD moved to August 2020. The Final 10

Study would then proceed according to the following estimated timeline, 11

assuming it is approved by the CPUC in an August final decision.12

TABLE 2ILLUSTRATIVE SCHEDULE FOR CONSIDERATION OF

BIFURCATED JOINT ESSENTIAL USE STUDY

LineNo. Study Activity Approximate Timeline

1 Ruling Granting Bifurcation February 10, 2020

2 Public Study Design Workshop March 18, 2020

3 Submittal of Final Joint Study Design April 11, 2020

4 Comments Opening: May 11, 2020Reply: May 26, 2020

5 Proposed Decision on Study and Cost Recovery Mechanisms

July 2020

6 Final Decision on Special Expedited, Bifurcated Proceeding on the Study

August 2020

7 Preparation for Study Initiation and Contracting

November 2020(+3 months from CPUC decision)

8 Joint Study Execution May 2021(+/6 months from contract issuance of contract, depending on additional task components selected)

9 Preparation of Draft Report and Web Tool September 2021(+/-4 months from Study Execution)

10 Public Workshop on How to use the Web Tool

Public Opening Comments on Draft Report

Public Reply Comments

October 2021 (+1 month from Release of Report and Tool)

November 2021 (+1 month from Workshop)

December 2021 (+1 month from Opening Comments)

11 Completion of Final Report and Submittal of Tier 2 AL

January 2022

12 Approval of AL March 2022

(PG&E-3)

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The estimated dates in the timeline presented above are dependent upon 1

the following assumptions: (1) the Web Tool for the 2019 RASS Study is 2

completed by November 2020; (2) consensus can be timely reached among the 3

stakeholders regarding the final EUS design; (3) the CPUC timely approves the 4

directed award to the contractor completing the RASS study; and (4) the CPUC 5

timely approves the final EUS design proposed by the Joint IOUs. If there are 6

changes in any of these assumptions, the estimated schedule above may need 7

to be lengthened in early 2022. Additionally, the CPUC will presumably consider 8

whether to initiate further proceedings to reach a decision on whether the current 9

baseline statutory percentage ranges remain a reasonable proxy based on the 10

EUS data, or, if not, what modifications it might recommend to the legislature as 11

a potential amendment to Pub. Util. Code Section 739.12

(PG&E-3)

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TABLE 32019 RASS QUESTION LIST

LineNo. Question

1 Home and Lifestyle

2 A1 What type of building exists at the service address on the front cover of this survey?

3 A2 Do you own or rent this home?

4 A3 How long have you lived at this address?

5 A4 Which of the following best describes this residence? (permanent/vacation)

6 A5 If this is a partial-year or vacation home, please indicate the months this home is typically occupied.

7 A6 Approximately what year was this residence built?

8 A7 How many bedrooms are in your home?

9 A8 How many square feet of living space are there in your residence

10 A9 Are your home’s exterior (outside) walls insulated?

11 A10 Is your home’s attic/ceiling insulated?

12 A11 If yes estimate the number of inches of attic/ceiling insulation.

13 A12 Choose the statements that best describe your windows.

14 A13 Has your home been remodeled in the past 12 months?

15 A14 If yes, what type of remodel did you do?

16 A15 For each of the following age groups, how many people including yourself usually live in this home?

17 A16 Generally speaking, how often does a member of this household use any major electrical appliances or equipment (e.g., clothes washer, electric range, dishwasher, air conditioner etc.) on weekdays from 12 noon to 6 p.m.?

18 A17 Is natural gas service from underground pipes from the gas utility available in your neighborhood?

19 A18 Do you have a natural gas line or hook-up to any part of your home?

20 A19 What utility do you pay for natural gas service to your home?

(PG&E-3)

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TABLE 32019 RASS QUESTION LIST

(CONTINUED)

LineNo. Question

21 EVs

22 A20 Does anyone in your household currently own or lease a plug-in battery EV or plug-in hybrid EV?

23 A21 How many EVs does your household own or lease?

24 A22 On an average day, how many total miles do you drive your EVs?

25 A23 How often do you charge your EV(s) at home work or somewhere else?

26 A24 Is your primary charger used at home a Level 1 (120 volt (V)) or Level 2(240 V)?

27 A25 When is/are the EV(s) normally charged using this primary charger?

28 Space Heating

29 B1 Do you pay to heat your home?

30 B2 What type of heating system do you use to heat this home?

31 B3 If your heating system(s) uses natural gas for fuel indicate whether it has a pilot light(s).

32 B4 How old is your main heating system?

33 B5 What type of thermostat does your main heating system(s) use?

34 B6 If your main heating system is controlled by a thermostat what is the average thermostat temperature usually set for each time period during the heating season?

35 B7 Has maintenance been performed on your main heating system in the past

36 B8 How many electric (plug-in) portable heaters do you use?

37 B9 How often do you use any additional heating system(s)

38 Space Cooling

39 Central Air Conditioning/Cooling

40 C1 Do you pay for central air conditioning/cooling for your home?

41 C2 What type and how many central air conditioning/cooling system(s) do you have in your home?

42 C3 How old is your main central air conditioning/cooling unit?

43 C4 What type of thermostat does your main air conditioning/cooling system(s) use?

44 C5 What is the typical thermostat temperature setting of your main central cooling system for each time period during the cooling season?

45 C6 Has maintenance been performed on your central air conditioning system in the past 12 months?

(PG&E-3)

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TABLE 32019 RASS QUESTION LIST

(CONTINUED)

LineNo. Question

46 Room Air Conditioning/Cooling (Window/Wall Units)

47 C7 Please tell us the characteristics of each room air conditioning/cooling unit below.

48 C8 Please indicate how often your room air conditioning/cooling unit(s) is/are turned on during the cooling season.

49 Water Heating

50 D1 Do you pay for heating water at your residence?

51 D2 What type of water heating systems do you use in your home?

52 D3 What is the typical hot water heater temperature setting?

53 D4 How old is your primary water heating system?

54 D5 How many total showers and baths are taken in your home on a typical day?

55 D6 Do you have low-flow showerheads installed in the shower(s)?

56 D7 Do the faucets in your home have water-saving aerators?

57 Laundry

58 E1 Do you have the use of laundry equipment in your home?

59 E2 What type of clothes washer do you have?

60 E4 For each wash temperature below, how many loads of clothes do you wash in your home during a typical week?

61 E5 What type of clothes dryer do you have?

62 E6 How old is your clothes dryer?

63 E7 For each dry temperature below how many loads of clothes do you dry in your home during a typical week?

64 Food Preparation

65 F1 Which of the following cooking appliances are used in your home?

66 F2 During a typical week how often do you use the following cooking appliances?

67 F3 Do you have a dishwasher?

68 F4 How old is your dishwasher?

69 F5 How many dishwasher loads are run in a typical week?

70 Refrigerators

71 G1 How many refrigerators do you have plugged in?

72 G2 Please tell us the characteristics of each refrigerator in the table below.

73 Door Style

(PG&E-3)

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TABLE 32019 RASS QUESTION LIST

(CONTINUED)

LineNo. Question

74 Freezers

75 H1 How many stand-alone freezers do you have plugged in?

76 H2 Please tell us the characteristics for each stand-alone freezer in the table below. (Style, size, age)

77 Spas and Hot Tubs

78 I1 Do you have the use of a spa or hot tub at your home?

79 I2 What fuel do you use to heat the spa or hot tub?

80 I3 How large is the spa or hot tub?

81 I4 Where is the spa located?

82 I5 Do you have an insulated cover on your spa or hot tub?

83 I6 How often do you run the filter pump on your spa or hot tub?

84 I7 Please indicate how often you heat your spa or hot tub in the winter and summer.

85 Pools

86 J1 Do you have the use of a swimming pool at your home?

87 J2 How large is your pool? (An average-size pool is about 5 ft. deep by 40 ft. long by

88 J3 How many hours per day do you operate your swimming pool filter?

89 J4 Which fuel do you use to heat your pool?

90 J5 Please indicate how often you heat your pool in the summer and winter.

91 J6 Which of the following attributes does your pool have? (Choose all that apply.)

92 Entertainment and Technology

93 K1 How many televisions and accessories do you use in this home?

94 K2 How many combined total hours are your televisions on each day?

95 K3 How many personal computer(s) (PC, Macintosh, etc.) do you use in this home?

96 K4 If you have one or more computer(s) in this home how many combined total hours are they turned on each day?

97 K5 Do you or someone else in your home operate a business and/or work from your home?

98 K7 How many of the following products do you use in this home?

99 Printer, Scanner, Copier or Multifunction machine

100 Tablet computer or e-reader (iPad or Kindle)

101 Hubs controllers (Amazon Echo, Google home, Apple HomeKit)

102 Smart home devices

103 “Smart” cell phone (iPhone or Android)

104 Other cell phone (flip phone candy bar phone)

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TABLE 32019 RASS QUESTION LIST

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LineNo. Question

105 High-speed modem for Internet (DSL/cable/satellite)

106 Home network (wired or wireless)

107 Uninterrupted Power Supply (UPS power backup)

108 Lighting

109 L1 What portion of light bulbs installed in the ceiling fixtures and lamps inside your home are the following types?

110 L2 How many lights inside your home are turned on during the following times of day?

111 L3 How many of the following lighting products do you use inside your home?

112 L4 How many of the following lighting products do you use outside your home?

113 Misc. Appliances

114 M1 How many of each of the following appliances or equipment do you use in your home?

115 M2 Do you use an electric well water pump to provide water for your home?

116 M3 Does your home also have access to city/county water?

117 M4 How do you use your well water?

118 M5 Select fuel type for any of the equipment that is used three or more hours per week

119 Sump pump, Shop tools, Electric welding equipment, Electric air compressor, Charger for large battery, Kiln for ceramics and pottery, Medical equipment (e.g., respirator)

120 M6 Do you have an electric bicycle, skateboard, wheelchair or golf cart at your home?

121 M7 Do you charge your electric wheelchair, cart, skateboard or bicycle at home?

122 M8 Do you use any other equipment or large appliance that consumes a significant amount of electricity or natural gas in your home?

123 M9 Please indicate if you have added any of the following appliances in the past 12 months. If the new item replaced an existing unit

124 M10 Please indicate if you have discarded any of the following appliances in the past 12 months. Include both items that were replaced and those that were discarded without being replaced.

125 Renewable Energy Technologies

126 M11 Which of the following renewable energy technologies are currently used at this residence?

127 No renewable energy technologies

128 Solar electricity/photovoltaic (PV) cells

129 Solar water heating (in-home water heated)

130 Battery storage connected to solar

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TABLE 32019 RASS QUESTION LIST

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LineNo. Question

131 Wind generator

132 Fuel cells

133 M12 In the next two years do you plan to install any of the following renewable technologies?

134 Household Information

135 N1 In addition to the home described in this survey do you own any other home in California that is occupied on a part-time basis by your family or as a vacation rental?

136 N2 Please provide the following information for your seasonal or vacation home that you own in California?

137 N3 What was the highest level of education completed by any head of household in the home?

138 N4 What is the primary language spoken in this home?

139 N5 Are any of the occupants of your home permanently disabled?

140 N6 Which of the following ethnic groups are represented by your head(s) of household?

141 N7 Please check the range that best describes your household’s total annual income.

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TABLE 42019 RASS DWELLING CLASSIFICATION QUESTIONS

ESSENTIAL USE MODEL DECISION GUIDELINESHOUSEHOLD SIZE

LineNo.

Square Footage

Number of Residents Additional

1 A7 How many bedrooms are in your home? X

2 A8 How many square feet of living space are there in your residence

X

3 A15 For each of the following age groups, how many people including yourself usually live in this home?

X

4 Building Features5

AgeConstruction

Materials Insulation Additional

6 A1 What type of building exists at your service address? (e.g., does it have shared walls and/or shared ceiling/floors)

X

7 A9 Are your home’s exterior (outside) walls insulated?

X

8 A10 Is your home’s attic/ceiling insulated? X

9 A11 If yes estimate the number of inches of attic/ceiling insulation.

X

10 A12 Choose the statements that best describe your windows. [PANE TYPE (number of layers of glass)]

X

11 A6 Approximately what year was this residence built?

X

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TABLE 52019 RASS QUESTION MATRIX

LineNo. 2019 RASS Survey Questions

Essential Use Model Decision Guidelines

Appliances

Efficiency Usage

1 EVs

2 A21 How many EVs does your household own or lease? X

3 Space Heating X

4 B2 What type of heating system do you use to heat this home? X

5 B4 How old is your main heating system? X

6 B5 What type of thermostat does your main heating system(s) use? X

7 Space Cooling

8 CENTRAL AIR CONDITIONING/COOLING X

9 C2 What type and how many central air conditioning/cooling system(s) do you have in your home?

X

10 C3 How old is your main central air conditioning/cooling unit? X

11 C4 What type of thermostat does your main air conditioning/cooling system(s) use?

X

12 ROOM AIR CONDITIONING/COOLING (Window/Wall Units) X

13 C7 Please tell us the characteristics of each room air conditioning/cooling unit below.

X

14 Water Heating

15 D2 What type of water heating systems do you use in your home? X

16 D4 How old is your primary water heating system? X

17 Laundry

18 E2 What type of clothes washer do you have? X

19 E5 What type of clothes dryer do you have? X

20 E6 How old is your clothes dryer? X

21 Food Preparation

22 F1 Which of the following cooking appliances are used in your home? X

23 F3 Do you have a dishwasher? X

24 F4 How old is your dishwasher? X

25 Refrigerators

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TABLE 52019 RASS QUESTION MATRIX

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LineNo. 2019 RASS Survey Questions

Essential Use Model Decision Guidelines

Appliances

Efficiency Usage

26 G1 How many refrigerators do you have plugged in? X

27 Age of your Refrigerator X

28 Freezers

29 H1 How many stand-alone freezers do you have plugged in? X

30 Age of your Freezer X

31 Spas and Hot Tubs X

32 I1 Do you have the use of a spa or hot tub at your home? X

33 I5 Do you have an insulated cover on your spa or hot tub? X

34 Pools

35 J1 Do you have the use of a swimming pool at your home? X

36 Entertainment and Technology

37 K1 How many televisions and accessories do you use in this home? X

38 K3 How many personal computer(s) (PC, Macintosh, etc.) do you use in this home?

X

39 K7 How many of the following products do you use in this home?

40 Printer, Scanner, Copier or Multifunction machine X

41 Tablet computer or e-reader (iPad or Kindle)

42 Hubs controllers (Amazon Echo, Google home, Apple HomeKit) X

43 Smart home devices X

44 “Smart” cell phone (iPhone or Android) X

45 Other cell phone (flip phone candy bar phone) X

46 High-speed modem for Internet (DSL/cable/satellite) X

47 Home network (wired or wireless) X

48 Uninterrupted Power Supply (UPS power backup) X

49 Lighting

50 L1 What portion of light bulbs installed in the ceiling fixtures and lamps inside your home are the following types?

51 Incandescent X

52 CFLs X

53 LEDs X

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TABLE 52019 RASS QUESTION MATRIX

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LineNo. 2019 RASS Survey Questions

Essential Use Model Decision Guidelines

Appliances

Efficiency Usage

54 L2 How many lights inside your home are turned on during the following times of day?

55 Morning X

56 Day X

57 Evening X

58 Night

59 L3 How many of the following lighting products do you use inside your home?

60 Fixtures on timers X

61 Fixtures on motion detectors or occupancy sensors X

62 Fixtures on a dimming switch X

63 "Smart" (connected) light bulbs X

64 HID (sodium vapor, metal halide) fixture X

65 Night lights

66 L4 How many of the following lighting products do you use outside your home?

67 Exterior incandescent fixtures X

68 Exterior compact fluorescent fixtures X

69 Exterior LED fixtures X

70 Low voltage landscape lighting system X

71 HID (sodium vapor, metal halide) fixture X

72 Fixtures on timers X

73 Fixtures on dusk-to-dawn sensors X

74 Fixtures on motion detectors X

75

76 Miscellaneous Appliances

77 M1 How many of each of the following appliances or equipment do you use in your home?

X

78 M2 Do you use an electric well water pump to provide water for your home? X

79 M5 Select fuel type for any of the equipment that is used three or more hours per week

80 Sump pump, Shop tools, Electric welding equipment, Electric air compressor, Charger for large battery, Kiln for ceramics and pottery, Medical equipment (e.g., respirator)

X

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TABLE 52019 RASS QUESTION MATRIX

(CONTINUED)

LineNo. 2019 RASS Survey Questions

Essential Use Model Decision Guidelines

Appliances

Efficiency Usage

81 M6 Do you have an electric bicycle, skateboard, wheelchair or golf cart at your home?

X

82 M7 Do you charge your electric wheelchair, cart, skateboard or bicycle at home? X

83 Renewable Energy Technologies

84 M11 Which of the following renewable energy technologies are currently used at this residence?

X

85 No renewable energy technologies X

86 Solar electricity/PV cells X

87 Solar water heating (In-home water heated) X

88 Battery storage connected to solar X

89 Wind generator X

90 Fuel cells X

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PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 9

ATTACHMENT A1

ESSENTIAL ENERGY PUBLIC WORKSHOP NOTES

Common Spark Consulting | www.common-spark.com | michelle@common-spark.com

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Public Workshop to Finalize Electric Essential Usage Study Design Meeting Notes | Submitted March 25, 2020

WWednesday, March 18, 2020 from 9:45am-2:00pm Online Workshop Hosted by: Pacific Gas and Electric Company Facilitated by: Michelle Vigen Ralston, Common SSpark Consulting

This document contains four sections: 1. Attendees2. Facilitator Takeaways3. Notes4. Appendix: Public Advocates additional comments and questions

Attendees Those in attendance are listed below. Other representatives from the organizations below may have also been in attendance, but are not included here if they did not speak during the meeting.

Name Organization Melissa Kasnitz Center for Accessible Technology Lee-Whei Tan CPUC-Public Advocates Office Christopher Hogan CPUC-Public Advocates Office Jieli Feng CPUC-Public Advocates Office Marshall Worsham CPUC-Public Advocates Office Paula Ham-Su DNV-GLClaire Palmgren DNV-GL Brian Arthur Smith Pacific Gas and Electric Co. Gail Slocum Pacific Gas and Electric Co. Hank Elgin Southern California Edison Carol Edwards Southern California Edison Cyndee Fang San Diego Gas & Electric Co. Jennifer Dowdell The Utility Reform Network David Cheng The Utility Reform Network Gabriela Sandoval The Utility Reform Network

Consultant Team: Michelle Vigen Ralston and Jack Chang, Common Spark Consulting

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Facilitator Takeaways

Data Collection

GGo beyond RASS: Main data collection for the Residential Appliance Saturation Survey (RASS) iscomplete, but the Essential Use Study could still recontact survey respondents for follow-up datacollection.

Qualitative Data to Enhance Identification of Underutilization: Consider how the study canincorporate qualitative data to supplement the quantitative data collection from RASS to helpidentify energy underutilization by low-income customers, either through follow-up surveysor through comparative analysis with other datasets. The Low Income Needs Assessment andsurvey questions from the study conducted under PUC Section 745 can provide guidance onquestions to identify underutilization.Medical Device Use and Energy Needs: Consider how the study can capture data abouthouseholds who have special medical-related energy needs, regardless if they are alreadyenrolled in the medical baseline program. This could be captured by asking about specificmedical equipment use needs or another method to be determined not based on equipmentuse. Some questions are included in RASS (Section M5), and other questions can be drawnfrom the baseline statute or other criteria used in practice by the utilities to establisheligibility for medical baseline.Equipment Type: Consider how to better capture the differences within certain energy usetypes such as different types of computers and swimming pools where energy use or billingmethods can vary. Stakeholders are invited to review questions K1-K7 and provide anyadditional items to include or specify.

Deliverables

Datasets and Web Tool: The underlying data in the study should be made public to the greatestextent possible. All participants agreed that parties should be able to access data in a format thatallows them to work with the data on their own to develop their own proposals around essentialuse.Workshop Training: A half-day or whole-day informal workshop should be held to teach partieshow to use the web tool, and a public PowerPoint and notes could provide instructions to thetool as well.Reporting: Develop a high-level report including methodology, caveats, limitations, and how thedata can support investigation of summary use. The report could also include summaryoutcomes, relevant trends, and comparative analysis – perhaps using the data to identifyallowances based on current baseline allowances guidance (basic, all-electric, climate zones,current definitions) to provide a “baseline” of the data results.

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Meeting Notes

1. Introduction

Michelle Vigen Ralston, the workshop facilitator, welcomed participants by asking one individual from each organization to introduce themselves and inviting them to participate in an ice breaker, naming a silver lining they’ve discovered while self-isolating during the ongoing coronavirus crisis. Ralston followed introductions by summarizing the goals of the workshop – level-setting on the progress and status of the Essential Use Study Draft; defining the scope of data collection; identifying other critical pieces of the essential energy use definition process; determining how the Residential Appliance Saturation Study (RASS) could support stakeholders’ priorities; and identifying the study’s final deliverables.

Gail Slocum of Pacific Gas and Electric Co. (PG&E) offered a procedural history of the Electric Essential Energy Usage Study. In August 2018, the California Public Utilities Commission (CPUC) ordered PG&E to develop a study plan as part of Phase 2 of the utility’s General Rate Case. The CPUC later asked Southern California Edison (SCE) and San Diego Gas & Electric (SDG&E) (together with PG&E, the “Joint Utilities”) to help develop the study plan along with PG&E. The Joint Utilities held two public workshops with interested parties in summer 2019. The Joint Utilities completed a joint study plan in November 2019.

The CPUC followed by holding a pre-hearing conference with PG&E and issued a scoping rule that ordered the essential use issue be bifurcated and expedited in PG&E’s General Rate Case Phase 2. The Joint Utilities need to receive stakeholder comments and file a final study plan by April 1.

Brian Arthur Smith, of PG&E, said the Joint Utilities concluded that the latest RASS, scheduled to be released later this year, would fulfill the CPUC’s order and be the most effective and expeditious way to complete the Essential Use Study. For the study, the Joint Utilities propose contracting with DNV-GL, the firm conducting the 2019 RASS as well as having run previous versions of the RASS. The Joint Utilities modeled their budget estimates off of the data collection study being conducted on San Joaquin Valley disadvantaged communities.

The CPUC’s Affordability Proceeding (R.18-07-006) released its revised Affordability Metrics Framework, which provides guidance on income and cost-related analysis and includes some discussion on essential energy use. Smith noted that the original Staff Proposal on Affordability Metrics Framework was also included in the Joint IOUs Draft Study Plan served in November. It was noted that the revised Staff Proposal had not been approved by CPUC decision yet, but that it was anticipated in June. Melissa Kasnitz of the Center for Accessible Technology (C for AT) noted that the timeline for a final CPUC decision on essential use could be up in the air with the coronavirus pandemic disruption.

The RASS is ideally conducted every three to four years, but Claire Palmgren of DNV-GL noted that it took a decade to follow up on the 2009 survey because the California Energy Commission (CEC) hit delays in finding funding and administering the request for proposal.

2. Data Collection

Ralston (Facilitator) opened discussion and sought input from stakeholders on data collection.

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RASS Study Data and the Essential Use Study

Kasnitz (C for AT) asked whether the Joint Utilities intended to accept more data as a follow-up to the RASS. She expressed concerns that data collection may have already ended and said more follow-up data such as qualitative research can help determine whether low-income households are underutilizing energy due to financial pressures or other causes. She said more data could also help assess which customers are enrolled in the California Alternate Rates for Energy (CARE) program, which serves low-income households, and whether people who earn more than CARE’s income threshold might still be underutilizing energy due to financial constraints. She also suggested looking at the Low Income Needs Assessment (LINA) for guidance, where energy insecurity and underutilization questions have already been asked in several survey iterations. She said the RASS could also ask about language spoken at home and whether the respondent was native versus foreign born.

Jennifer Dowdell, of The Utility Reform Network (TURN), said follow-up data collection could also better capture the energy usage of medical baseline consumers. Without such follow-up data, she said the study could still use existing demographic data to cross-reference customer types to get a better sense of energy usage by medical baseline customers. She added that the study should address how it will or will not handle possible long-term disruptions in work schedules and energy use patterns due to the coronavirus pandemic. Kasnitz concurred that employers might start allowing more telecommuting after the pandemic eases, which would drive up household energy use.

In response to Kasnitz’s question about the completion of the RASS and the opportunity for additional questions, Slocum (PG&E) clarified that the Joint Utilities study plan submitted in November 2019 had specified that the RASS would be issued in March 2020 with the assumption that data collection would be completed by then. However, she said the Joint Utilities could still fill in gaps in the existing questionnaire with follow-on surveys. She also addressed Dowdell’s coronavirus concerns, saying the study should use a baseline built off energy use patterns before the coronavirus crisis. If the pandemic permanently changes energy use patterns, the utilities will have to return to the Commission about possibly rerunning the RASS.

Smith (PG&E) added that DNV-GL had already combined RASS survey research data collected from tens of thousands of customers across the state with utility-provided billing and monthly consumption data; the results of the RASS were to be published soon. He underscored that the Joint Utilities could recontact RASS participant customers for follow-on research if new data needs emerged for the Essential Use Study. He said PG&E had added a few line items for additional data collection in its study budget.

Lee-Whei Tan of the CPUC said needed data have already been collected for the RASS survey and more money for data collection should not have to be allocated for the project. She also said the RASS could use examples of energy underutilization survey questions from a survey conducted pursuant to PUC Code745 examining households facing economic hardship.

Paula Ham-Su of DNV-GL said the current RASS has an explicit and implicit sample design that can help detect energy underutilization. For example, the tool can identify similarly sized households living in similar-sized structures but using different amounts of energy.

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Medical Baseline

Kasnitz (C for AT) said the RASS questionnaire should include detailed questions about the types of medical devices in households that run on electricity and ask for descriptions. She said the medical baseline program has been underutilized and that many eligible people are not enrolled. She said the program has generally not done enough to publicize its offerings and enroll enough eligible people. Due to that underutilization, the collected RASS data should look at people using the medical baseline program but also include the equipment use patterns of needy populations in the broader community that are not enrolled in the program.

Ham-Su (DNV-GL) said the study captures medical baseline households by using utility records but that such households are not part of the sample design. She also said the numbers of people on medical baseline is low. Slocum (PG&E) responded that the miscellaneous appliance questions in the study plan, section M5, talks about respirators and medical equipment. Dowdell (TURN) added that the M5 section also asks whether electricity or natural or bottled gas is used for respirators or any kind of medical equipment, but that the section doesn’t ask about specific equipment types.

Hank Elgin, of SCE, said the medical baseline program is a separate allowance provided on top of regular baseline allowances and includes all medical related usage. Being additional, medical baseline doesn’t fit the same 50% to 60% allocation criteria that the regular baseline includes. He also said the current baseline allocation method is easy to update. If the medical baseline information is included in the affordability metric on a regular basis, the Essential Use Study should be capable of being updated on a regular basis with those data. Running separate one-off studies poses lots of costs and operational difficulties. Overall, he said the RASS is exceptionally thorough and detailed.

Slocum (PG&E) gave a quick run-through of the background of the medical baseline program, which began when the original Lifeline energy statute sought to determine how much energy was used by individual appliance types. That statute also tried to create tier differentials for the basic residential rate based on that assessment. The methodology switched to an overall average percentage baseline structure with differentiation only for seasonality and whether the house was all electric or not. At that point, the medical baseline became a lump sum amount of additional baseline. She suggested that going forward, following up on the RASS could include creating detailed questions about medical equipment, as required in the original Lifeline statute. The legislature switched approaches because maintaining a list of equipment became cumbersome.

Kasnitz also recommended including a list of medical equipment in the survey. She reminded participants that the medical baseline program statue has a list of medical conditions that establish eligibility although utilities don’t demand adherence to those categories of conditions. Slocum said utilities often identify any needed medical equipment to establish eligibility rather than medical conditions as determinants for medical baseline eligibility. She added that the medical baseline population often come in and out of the program.

Ham-Su said the medical baseline program represented a small part of the total RASS population and that medical equipment wasn’t a necessarily accurate metric either of health-related energy needs. For example, she said someone could be homebound without medical equipment but still use more energy due to being home all day.

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Ralston (Common Spark) offered that stakeholders were envisioning how the Essential Use Study data collection could include seeing how medical equipment broadly is affecting overall usage data. Smith (PG&E) suggested using medical baseline as another attribute in the modeling and looking at how much electricity use grows for medical baseline customers. Ham-Su said medical baseline is not in the current scope of work but the study could look at how many people have identified their use of medical equipment and whether that number was high enough to make a reliable calculation.

Lee-Whei Tan (CPUC) reminded workshop participants that a past questionnaire had been developed during the implementation of time-of-use rates asking about household energy use. She said those questions could be used as model for the RASS. Slocum agreed that using the past questionnaire could save extra time and work. Marshall Worsham, of the CPUC, also noted that research issued by Lawrence Berkeley National Laboratory – EPIC Project EPC-15-024 - on electrical device use included a list of equipment types serving the health and safety needs of residential customers. He also noted that the CPUC order required collecting building information such as construction materials. Elgin responded that the RASS does ask about the age of houses and building standards to identify building attributes.

Christopher Hogan, of the CPUC, said the RASS uses forecasting zones that are different from utility baseline instances or Title 24 territory zones. He sought confirmation from DVN-GL that the RASS’ sample sizes produce valid statistical results for utility baseline territories. Ham-Su confirmed that the sample sizes likely did produce statistically significant results but that would have to be confirmed. Slocum said SCE and SDG&E use the same baseline territory boundaries as the CEC but that PG&E’s baseline territories differ to some degree.

Equipment Types

Carol Edwards, of SCE, noted that energy use varied depending on different types of equipment even within a single equipment category. For example, typical computers use less electricity than computers designed for gaming. She said gaming computers shouldn’t be considered essential energy use. Similarly, electric bikes might be lumped in with essential equipment such as wheelchairs in survey questions. Energy used to maintain swimming pools could also vary, given the differences in how energy is billed for owners and renters.

Palmgren (DVN-GL) responded that some of the RASS questions were broad in their scope. For example, one yes/no question asked whether the household had an electric bike, skateboard or electric wheelchair.

Slocum (PG&E) noted that under entertainment technology, questions K1 through K7 ask whether the household uses a specific list of equipment such as scanners, copiers and hub computers.

Hogan (CPUC) noted that the RASS might need to be expanded to include additional participants depending on whether electric vehicles (EV) and solar generation will be included as essential use. Ham-Su (DNV-GL) responded that not all electric vehicle drivers sign up for special EV electricity rates, which makes identifying and tracking EV-using customers more difficult. She said if EVs are defined as an essential use, DNV-GL would need to follow up, not necessarily in the form of additional questions but possible with other data sources. Slocum concurred that many EV drivers don’t use the special EV rate. Cyndee Fang (SDG&E) said the RASS already asks about EVs such as the number of EVs in the household

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and how long they charge for, which means they capture the EV usage of non-EV rate customers. She said people should look at the questions provided in Table 9.A.2 to see what’s already in the RASS.

3. Deliverables and Budget

Web Tool and Datasets

Smith (PG&E) demonstrated the current RASS web tool, which he said would be the Essential Use Study’s main deliverable. The RASS web tool features data types such as age, head of household, size of household and type of housing. Users can also use the tool to drill down on data that differentiate between residence types, age of housing and other details. Users can design a query to determine the essential use of a particular appliance, type of house, income level and other details to produce energy tables and reports. The tool provides results in PDF data tables that are cut in pre-determined ways. The Joint Utilities propose to ask DNV-GL to add to the RASS web tool any additional data that would still be collected for the Essential Use Study.

Dowdell (TURN) said the collected data need to be publicly available and able to be downloaded in a form that users can analyze on their own spreadsheets. She asked about the functionality of the data and whether the tool will function like a data cube, but with constraints on the granularity of the data that can be assessed. She also said U.S. Census data could be matched with essential use data to provide basic demographic and income information as further context.

Palmgren (DNV-GL) said underlying anonymized household data would be available upon request from the California Energy Commission, and that DNV-GL was not authorized to distribute those data. Web tool queries, however, produce live saturation tables with aggregated data that can be exported to Excel. Unit Energy Consumption are only available in static tables due to their sample sizes. Ham-Su (DNV-GL) said underlying data in already published tables could also be made available for use in Excel. She said that once data are approved for release, they can be released in any format desired by users. She added that U.S. Census American Community Survey data were already attached to the RASS database but can’t be matched to specific households.

Slocum (PG&E) noted, as an alternative method for parties to receive more granular datasets, that in certain CPUC proceedings, PG&E already uses proprietary models with confidential data in which parties can work with the data at a high level of granularity using a non-disclosure agreement. Elgin (SCE) said the goal of the web tool was to let users access the same dataset and sources and produce their own results and definitions of essential energy usage.

Public Workshop and Tool Training

Smith (PG&E), earlier in the meeting, had presented the San Joaquin Valley data collection study as a model for estimating a budget for the Essential Use Study. He noted that the San Joaquin study included funding for a stakeholder presentation but in the Essential Use Study case, a stakeholder presentation might not be as useful and so anticipated allocating minimal if any funding in the budget for such a presentation. Slocum (PG&E) proposed holding a full-day or half-day workshop, not a formal presentation, that would teach parties how to use the web tool. Dowdell (TURN) agreed that such a

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workshop would be helpful. Palmgren (DNV-GL) suggested producing a user guide for the web tool as well. She noted that DNV-GL was still receiving inquiries from users about how to use the 2009 web tool.

After discussion, participants agreed a web tool workshop with a PowerPoint presentation and notes would offer enough information to teach people how to use the tool. Tan (CPUC) said the presentation could include sample results that would show people how to work with the underlying model by manipulating the tool. Smith said a report could accompany the web tool largely to show how the tool was put together and could be used. Slocum added that a mechanism in the tool could help parties collaborate once they see the data.

Report

Smith (PG&E) also noted that it didn’t seem like a report would contain much if the core of the study is the data collection and web tool. A report could include methodology, and perhaps analysis of essential use based on current definitions and approaches, but that the Joint Utilities were not anticipating putting forth a full analysis and proposal for an essential use definition.

Dowdell said TURN is interested in being able to construct its own interpretations with the dataset and wouldn’t find as much value in a report with “a billion slices and dices.” She said the Joint Utilities should still use the report as a vehicle to offer their viewpoints on the study, even if preliminary, along with the scope and caveats of the data.

Tan (CPUC) said the report’s high-level outcomes could be organized by climate zones with cuts based on CARE, non-CARE medical customers and other criteria used by the CPUC’s Affordability Order Instituting Rulemaking. Elgin (SCE) suggested presenting the results by current stratification of baseline allowances.

Slocum (PG&E) said the study will have to determine which percentage of average use for climate zones to set for the average baseline allocation, somewhere from 50% to 60%. Dowdell pointed out that 60% is a placeholder in the Affordability OIR pending completion of studies.

4. Wrap-up

Ralston quickly summarized the work of the stakeholders, from the presentation by PG&E to the discussion on data collection to deliverables. She noted that the facilitation team would be writing up notes so stakeholder input would be documented for the Joint Utilities as they work to complete their Final Study Plan by April 1.

Additional questions and comments were invited to be sent to Michelle Vigen Ralston at michelle@common-spark.com for inclusion in the workshop notes.

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Attachments: Public Advocates Office Questions and Suggestions

The following was submitted on March 20 to Common Spark Consulting by Christopher Hogan for inclusion in these notes.

The Public Advocates Office:Essential Use Study Plan Questions and Suggestions

Budget:1. What is the difference between deliverables “Optional Phase II Data Collection” and “Data

Collection Sampling & Implementation Plan”?a) If there will be additional data to collect, is this cost going to be covered by the budget

for “Optional Phase II Data Collection”?b) If yes, why is there still a need to budget for “Data Collection Sampling &

Implementation Plan” when the RASS data is going to be leveraged for the essential usestudy?

2. If the project for the essential use study is less complicated than the SJV DAC project, the costfor “Preliminary Results Draft Memo,” “Draft and Final Report,” and “Final ResultsPresentation” should be less expensive than the SJV DAC. However, these deliverables arecurrently allocated a maximum of 100% of the SJV DAC project. The IOUs should work withDNV GL to provide a reasonable estimate of the budget for this study.

Data Needs:3. For Electric Vehicle, Net Metering, and all electric customers:

a) There should be a filter to include or separately analyze these customers from theessential use analysis, due to their less common usage needs, in the proposed web tool.

4. Anonymized raw data should be provided to all parties, so that parties can perform their ownessential use analysis.

5. Given the RASS survey sample size is scaled to the CEC Forecasting Zones (which are not thesame as the CEC Title 24 Zones and Baseline territories):

a) Is there an adequate sample size to produce accurate estimates of essential usage forcustomers by utility baseline territory?

b) Is there an adequate sample size to estimate essential usage for customers by utilitybaseline territory and:

1. CARE/FERA/Non CARE-FERA status2. All Electric versus basic customer status3. Net metering status4. Electric Vehicle owner status5. Medical Baseline status

Study Proposal:6. Is conditional demand modeling the best approach for estimating essential use? What’s the

justification? What other modeling approaches have been considered?a) Alternative methods that were considered should be included in the final report.

7. The Essential Use Study proposal filed by the utilities should include justification for leaving outany factors or variables that were ordered in (D.) 18-08-013 to be included in this study.

(PG&E-3)

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(PG&E-3)

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 9

ATTACHMENT A2

RASS SURVEY INSTRUMENT

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(PG&E-3)

9-AtchA2-1

Your household can help improve the reliability of California’s future energy needs by completing this survey today. This survey was sent to a limited number of households so each response counts!

To simplify and accelerate the survey submission process, we invite you to complete the survey online. Please visit the following secure website: https://calhes.com

Alternatively, you may fill-out this survey booklet. Using these instructions, please:

1. Use a pencil or a ball-point black orblue ink pen to fill out the survey.

2. Choose only one answer for eachquestion unless the instructionsstate otherwise.

3. Fill in the circles completely.4. To change your answer, erase

completely or clearly cross outunintended response, as illustratedhere:

5. Information in blue ink is printed onthe survey to help clarify or directyou to the next question based onyour response.

6. When you are finished, pleasereturn the survey in the enclosedpostage-paid envelope or mail it to:

CA Home Energy SurveyProcessing Center2672 Dow Ave.Tustin, CA 92780

Complete the survey in the next week for the address that is printed on the front page of this booklet. When answering the questions, provide responses that represent all household members, not just the person completing the survey.

Do your best to answer all questions, if you do not know the answer to one of the questions, move on to the next one.

Need assistance or have a question? Please email or call our survey contractor at support@calhes.dnvgl.com or call the customer support line at 1 (866) 363-7448. DNV GL Energy Insights USA, Inc. has been hired by the Energy Commission to manage this study they are available Monday through Friday, 8:30 a.m. to 5:00 p.m. Pacific time.

Esta encuesta tambien esta disponible en Español por el internet, si usted prefiere llenarla de ese modo. Por favor visite la página https://calhes.com. Para poder realizar nuestro análisis de energía, necesitamos que sus respuestas sean solo sobre su casa. Antes de empezar la encuesta por internet, necesitará información disponible en este libreto.

On behalf of the Energy Commission and our study sponsors we look forward to receiving your information and thank you for your participation.

Sponsored by: California Energy CommissionPacific Gas and Electric Southern California EdisonSan Diego Gas and Electric Los Angeles Dept. of Water and PowerSoCalGas Sacramento Municipal Utility District

(PG&E-3)

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Your Home & LifestyleA1 What type of building exists at the service address on the front cover of this survey

(after the “For Service At:” on the cover)?Single-family detached house Number of stories: 1 2 3 or more Townhouse, duplex, or row house (shares walls with neighboring unit, but not roof or floor)Apartment or condominium (2 – 4 units)

Apartment or condominium (5 or more units)Mobile homeOther (Describe: ________________________________)

A2 Do you own or rent this home?Own / buying Rent / lease

A3 How long have you lived at this address?1 year or less 6 years 11 years 16 – 20 years2 years 7 years 12 years 21 – 30 years3 years 8 years 13 years More than 30 years4 years 9 years 14 years5 years 10 years 15 years

A4 Which of the following best describes this residence?This is my permanent year-round residence. (Go to A6.)This is my partial-year or seasonal residence. This is my vacation home and is generally used only by my family. This is a vacation rental home.

A5 If this is a partial-year or vacation home, please indicate the months thishome is typically occupied. (Mark all months that apply.)

Jan Mar May Jul Sept NovFeb Apr Jun Aug Oct Dec

A6 Approximately what year was this residence built?Before 1940 1960-1969 1979-1983 2000-20051940-1949 1970-1974 1984-1991 2006-20121950-1959 1975-1978 1992-1999 2013-2019

A7 How many bedrooms are in your home?No bedrooms (studio apartment) 3 6 91 bedroom 4 7 102 bedrooms 5 8 More than 10

A8 How many square feet of living space are there in your residence, includingbathrooms, foyers and hallways? (Exclude garages, basements and unheatedporches.)

Less than 250 1001 – 1250 2501 – 3000250 – 500 1251 – 1500 3001 – 4000501 – 750 1501 – 2000 4001 – 5000751 –1000 2001 – 2500 More than 5000

(PG&E-3)

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A9 Are your home’s exterior (outside) walls insulated?Yes, all walls Yes, some walls No Unknown

A10 Is your home’s attic/ceiling insulated?Yes A11 If yes, estimate the number of inches of attic/ceiling insulation.No 0 – 3 inches (R-value less than R-10)Unknown 4 – 6 inches (R-11 to R-19)

7 – 10 inches (R-20 to R-30)More than 10 inches (R-31 or higher)

A12 Choose the statements that best describe your windows.PANE TYPE (number of layers of glass)

All or most are single pane

All or most are double pane

All or most are triple pane

Mixture of single,double and/or triplepane

FRAME TYPEAll or most have vinyl

framesAll or most have wood

framesAll or most have metal frames

A13 Has your home been remodeled in the past 12 months?No (Go to A15.)Yes A14 If yes, what type of remodel did you do? (Choose all that apply.)

Room addition, added square footage to homeKitchen or bath remodel Re-built most of the homeOther

A15 For each of the following age groups, how many people, including yourself,usually live in this home?

Number of People Usually Living In This HomeAge None 1 2 3 4 5 6 7 Over 75 and under6 – 1819 – 3435 – 5455 – 6465 and over

A16 Generally speaking, how often does a member of this household use any majorelectrical appliances or equipment (e.g., clothes washer, electric range, dishwasher, air conditioner, etc.) on weekdays from 4 pm to 9 pm?

Frequently (3 – 5 weekdays per week)Occasionally (1 – 2 weekdays per week)Rarely or Never (Less than 1 weekday per week)

A17 Is natural gas service from underground pipes from the gas utility available inyour neighborhood?

Yes No (Go to A20.)

A18 Do you have a natural gas line or hook-up to any part of your home?Yes No

(PG&E-3)

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A19 What utility do you pay for natural gas service to your home?Pacific Gas & Electric (PG&E)San Diego Gas & Electric (SDG&E) SoCalGas(“The Gas Company”)

Southwest Gas CorporationCity of CoalingaCity of Long Beach Gas Department Not sure

Electric VehiclesA20 Does anyone in your household currently own or lease a plug-in battery electric

vehicle or plug-in hybrid electric vehicle?Yes No (Go to B1)

A21 How many electric vehicles of each type does your household own or lease?1 2 3 or more

Plug-in electric vehicle (e.g. Tesla, Honda Clarity, Toyota Prius Prime, Chevy Bolt, Nissan Leaf, BWM i3)Hybrid electric plug-in vehicle (e.g., Chevy Volt, Ford Fusion Energi)

A22 On an average day, how many total miles do you drive your electric vehicles? (Choose one answer for the total miles for all electric vehicles for the average weekday, and one answer for the average weekend day)

Monday-Friday

Saturday - Sunday

Less than 20 miles21-40 miles41-60 miles

61-100 milesMore than 101 miles

A23 How often do you charge your electric vehicle(s) at home, work or somewhere else? (Choose one answer for each location that you charge the vehicles)

Home Work Some-where Else

Daily5-6 times per week3-4 times per week1-2 times per week

Less than once a week

A24 Is your primary charger used at home a Level 1 (120V) or Level 2 (240V)?Level 1 (120V) standard wall outlet – slower chargeLevel 2 (240V) charger - outlet like clothes dryer uses – faster charge Don’t knowDo not charge at home (Go to B1)

A25 When is/are the EV(s) normally charged at home using this primary charger?(Choose all that apply.)

Morning (6am-9am)Day (9am–5pm)Evening (5pm–9pm)Night (9pm–6am)

(PG&E-3)

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Space HeatingB1 Do you pay to heat your home?

Yes No, it is part of my rent/condo fee (Go to B8.)No, do not have a heating system (Go to B8.)

B2 What type of heating system do you use to heat this home? (If you use more than one heating system, mark the system that you use the most as “Main Heating” and mark all other systems as “Additional Heating.”)

MainHeating

Additional Heating

(Mark only ONE BOX below)

(Mark ALL BOXES that apply)

NATURAL GAS (from gas utility)Central forced-air furnace (fan circulates hot air through

air ducts)Floor or wall heater/furnaceHot water radiator (steam, hot water, fin tubes)Fireplace (Gas)Other system type

ELECTRICResistance (baseboard/ceiling/floor/wall)Central forced air furnace (fan circulates hot air through

air ducts)Central heat pump (heats and cools)Through-the-wall heat pump (looks like a window/wall

air conditioner, but also provides heat)Portable heatersOther system type

BOTTLED GAS (propane, LP)Central forced air furnace (fan circulates hot air through

air ducts)Floor or wall heater/furnaceHot water radiator (steam, hot water, fin tubes)Other system type

WOODWoodstove/pellet stove/fireplace insertFireplace (Wood-burning)

SOLARSolar – no backupSolar – natural gas backupSolar – propane backupSolar – electric backup

OTHER FUEL(Describe):___________________

B3 If your heating system(s) uses natural gas for fuel, indicate whether it has a pilot

light(s).Main gas heating Yes, pilot light on all

yearYes, pilot light on in winter only

No pilot light

Secondary gas heating

Yes, pilot light(s) on all year

Yes, pilot light(s) on in winter only

No pilot light(s)

(PG&E-3)

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B4 How old is your main heating system?Less than one year 4 – 8 years 14 – 30 years1 – 3 years 9 – 13 years Over 30 years

B5 What type of thermostat does your main heating system(s) use?Smart thermostat (Can be used with home automation systems and may sense when you are home, e.g., Nest, Lyric, Sensi or Ecobee)Programmable thermostat (Can set heater to different temperatures for different times)Non-programmable thermostat (Can turn heater on/off and set temperature by hand.) No thermostat (Simple on/off control or steam valve) (Go to B7.)

B6 If your main heating system is controlled by a thermostat, what is the averagethermostat temperature usually set for each time period during the heating season? (Choose one for each time period. Provide the average setting if it varies.)

Off Below 55 F

55 –60 F

61 –65 F

66 –70 F

71 –75 F

Over 75 F

Morning (6am-9am)Day (9am-5pm)Evening (5pm-9pm)Night (9pm-6am)

B7 Has maintenance been performed on your main heating system in the past12 months?

Yes No

B8 How many electric (plug-in) portable heaters do you use?I don’t use portable heaters1 portable heater

2 portable heaters 3 or more portable heaters

B9 How often do you use any additional heating system(s), including portable heaters,during the heating season?

No additional heatingRarely (once per month)Sometimes (once per week)

Often (2 to 4 days per week)Always (5 to 7 days per week)

Space Cooling CENTRAL AIR CONDITIONING/COOLING

C1 Do you pay for central air conditioning/cooling for your home?Yes No, it is part of my rent/condo fee (Go to C7.)

No, do not have central air conditioning (Go to C7.)

C2 What type and how many central air conditioning/cooling system(s) do you have inyour home? (Zoned thermostats control different zones (spaces) within the home).

Number of Central Cooling Systems

Main SystemControlled Using a Zoned Thermostat

1 2 3 or moreCentral air conditionerCentral evaporative (swamp) coolerHeat pump (heats and cools)Mini-split or “ductless”

(PG&E-3)

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C3 How old is your main central air conditioning/cooling unit?Less than one year 4 – 8 years 14 – 30 years1 – 3 years 9 – 13 years Over 30 years

C4 What type of thermostat does your main air conditioning/cooling system(s) use?Smart thermostat (Can be used with home automation systems and may sense when

you are home, e.g., Nest, Lyric, Sensi or Ecobee)Programmable thermostat (Can set air conditioner (AC) to different temperatures for

different times) Non-Programmable thermostat (Can turn the AC on/off and set temperature by hand) No thermostat (Simple on/off control) (Go to C6.)

C5 What is the typical thermostat temperature setting of your main central cooling system for each time period during the cooling season?(Choose one answer for each time period.)

Off Below 68 F

68 – 69 F 70 – 73 F 74 – 76 F 77 – 80 F Over 80 F

Morning (6am–9am)Day (9am-5pm)Evening (5pm-9pm)Night (9pm-6am)

C6 Has maintenance been performed on your central air conditioning system in thepast 12 months?

Yes No

ROOM AIR CONDITIONING/COOLING (Window/Wall Units)

C7 Please tell us the characteristics of each room air conditioning/cooling unit below.

No room air conditioning/cooling units (Go to D1.)

Unit 1 Unit 2 Unit 3Type of Room AC/Cooling Unit

Window/wall/portable air conditionerWindow/wall heat pumpWindow/wall evaporative (swamp) cooler

Age of Room AC/Cooling UnitLess than one year1 – 3 years4 – 8 years9 – 13 yearsMore than 13 years

C8 Please indicate how often your room air conditioning/cooling unit(s) is/are turnedon during the cooling season. (Choose one answer for each time period.)

Time PeriodNever Rarely

(1-2 daysper week)

Sometimes(3-4 days per week)

Often(5-6 daysper week)

Always(7 days

per week)Morning (6am-9am)Day (9am–5pm)Evening (5pm–9pm)Night (9pm–6am)Hot weekday afternoon (noon–6pm)

(PG&E-3)

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Water HeatingD1 Do you pay for heating water at your residence?

Yes No, it is part of my rent/condo fee (Go to D5.)No hot water heater (Go to D5.)

D2 What type of water heating systems do you use in your home?Main

Water Heater(Mark only ONE

BOX in this column)

Additional Water Heater(s)(Mark ALL BOXES

that apply)NATURAL GAS

Standard tankWhole house tankless systemHigh-efficiency condensing (with plastic vent pipe)

ELECTRICStandard tankHeat pumpWhole house tankless systemPoint-of use tankless system

PROPANE Standard tankWhole house tankless system

SOLAR With no backup systemWith natural gas backupWith propane backupWith electric backup

OTHER FUELDescribe:___________________

D3 What is the typical hot water heater temperature setting? (Medium is the standardfactory setting.)

Low (below 130°F) Medium (130°F – 150°F) High (over 150°F)

D4 How old is your primary water heating system?Less than one year 4 – 8 years 14 – 30 years1 – 3 years 9 – 13 years Over 30 years

D5 How many total showers and baths are taken in your home on a typical day?0 1 2 3 4 5 6 7 8 9 10 or more

Showers / dayBaths / day

D6 Do you have low-flow showerheads installed in the shower(s)? (Low-flowshowerheads use 1.8 gallons per minute or less and have been standard since 1993.)

Yes, all showers Yes, some showers No

D7 Do the faucets in your home have water-saving aerators? (Aerators are add-ondevices that reduce the water usage by mixing air into the water stream.)

Yes, all faucets Yes, some faucets No

(PG&E-3)

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LaundryE1 Do you have the use of laundry equipment in your home?

Yes No, laundry facilities are located in a common area of the building. (Go to F1.)I do not use laundry facilities in my building (Go to F1.)

E2 What type of clothes washer do you have? (Do not include machines in common areas.)

Top loading washer Front loading washer

E3 How old is your clothes washer?Less than one year1 – 5 years

6 – 8 years 9 – 15 years

16 – 30 yearsOver 30 years

E4 For each wash temperature below, how many loads of clothes do you wash in your home during a typical week?

Number of Clothes Washer Loads per Week0 1 2 3 4 5 6 7 8 9 10 or more

Hot waterWarm waterCold water

E5 What type of clothes dryer do you have? (Do not include machines in common areas.)I do not have a clothes dryer Natural gas dryer

Electric dryerBottled gas dryer (Propane, Butane, LP)

E6 How old is your clothes dryer?

Less than one year1 – 5 years

6 – 8 years 9 – 15 years

16 – 30 yearsOver 30 years

E7 For each dry temperature below, how many loads of clothes do you dry in your home during a typical week?

Number of Clothes Dryer Loads per Week0 1 2 3 4 5 6 7 8 9 10 or more

High heatMedium heatLow heat

Food PreparationF1 Which of the following cooking appliances are used in your home? (Choose all that

apply.)Type of Fuel Age In Years

Cooking Appliance

Natural Gas

Elec-tric

Bottled Gas Other

0–5 yrs

6–10yrs

11–15years

Over 15 years

Cooktop, stovetop or range Oven(s) Outdoor ovenOutdoor grill/BBQMicrowave Oven

(PG&E-3)

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F2 During a typical week, how often do you use the following cooking appliances?

NeverRarely

(less than onceper week)

Occasionally(1 – 2 timesper week)

Sometimes(3 – 4 timesper week)

Often(5 – 7 timesper week)

Cooktop, stovetop or range Oven(s) Microwave OvenOther

F3 Do you have a dishwasher? Yes No (Go to G1.)

F4 How old is your dishwasher?Less than one year1 – 5 years

6 – 8 years 9 – 15 years

16 – 30 yearsOver 30 years

F5 How many dishwasher loads are run in a typical week?None1

23

45

67

89 or more

Refrigerators G1 How many refrigerators do you have plugged in?

0 (Go to H1.) 1 2 3 or more

G2 Please tell us the characteristics of each refrigerator in the table below. (Choose one for each section for each refrigerator.)

Refrig 1 Refrig 2 Refrig 3Door Style

Single-doorTop Freezer – Bottom RefrigeratorTop Refrigerator – Bottom FreezerSide-by-side

Size, in Cubic FeetMini (under 13 cu. ft.)Small (13 – 16 cu. ft.)Medium (17 – 19 cu. ft.)Large (20 – 23 cu. ft.)Very large (over 23 cu. ft.)

Age of your RefrigeratorLess than two years2 – 7 years8 – 10 years11 – 20 yearsMore than 20 years

Other FeaturesThrough-the-door ice and water dispenser

(PG&E-3)

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Freezers H1 How many stand-alone freezers do you have plugged in?

(Do not include freezers that are part of your refrigerator.)0 (Go to I1.) 1 2 or more

H2 Please tell us the characteristics for each stand-alone freezer in the table below.Freezer 1 Freezer 2

StyleUpright, frost-freeUpright manual defrostChest frost-freeChest manual defrost

Size, in Cubic FeetSmall (under 13 cu. ft.)Medium (13 – 16 cu. ft.)Large (over 16 cu. ft.)

Age of your FreezerLess than two years2 – 7 years8 – 10 years11 – 20 yearsMore than 20 years

Spas and Hot TubsI1 Do you have the use of a spa or hot tub at your home?

(Do not include whirlpool tubs in your bathroom.)Yes, and I pay for its energy useYes, but it is in a common area and I do not pay for its energy use (Go to J1.)No spa or hot tub (Go to J1.)

I2 What fuel do you use to heat the spa or hot tub?ElectricityNatural gas

Solar and electricitySolar and natural gas

Bottled gas (propane, butane, LP)Other

I3 How large is the spa or hot tub?Small (3 people or fewer) Medium (4 – 6 people) Large (7 or more people)

I4 Where is the spa located?Outside, in the ground Outside, above ground Indoor spa

I5 Do you have an insulated cover on your spa or hot tub?Yes No

(PG&E-3)

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I6 How often do you run the filter pump on your spa or hot tub? Summer (May – Oct.) Winter (Nov. – April)

Morning(6am-10am)

Mid-Day(10am-6pm)

Night(6pm-6am)

Morning(6am-10am)

Mid-Day(10am-6pm)

Night(6pm-6am)

NeverRarelyOnly when we use it1 – 3 hours every day4 – 6 hours every day

I7 Please indicate how often you heat your spa or hot tub in the winter and summer.

Summer (May – Oct.) Winter (Nov. – April)Morning

(6am-10am)Mid-Day

(10am-6pm)Night

(6pm-6am)Morning

(6am-10am)Mid-Day

(10am-6pm)Night

(6pm-6am)Never0 – 2 times per month3 – 8 times per month9 or more times per monthMaintain set temperature

PoolsJ1 Do you have the use of a swimming pool at your home?

Yes, and I pay for its energy useYes, but it is in a common area and I do not pay for its energy use (Go to K1.)No pool (Go to K1.)

J2 How large is your pool? (An average-size pool is about 5 ft. deep by 40 ft. long by 20 ft. wide and holds 30,000 gallons of water.)

Less than 20,000 gallons 20,000 – 40,000 gallons More than 40,000 gallons

J3 How many hours per day do you operate your swimming pool filter?Hours Summer (May – Oct.) Winter (Nov. – April)

Morning(6am-10am)

Mid-Day(10am-6pm)

Night(6pm-6am)

Morning(6am-10am)

Mid-Day(10am-6pm)

Night(6pm-6am)

None1 – 23 – 45 – 78 – 12

J4 Which fuel do you use to heat your pool? Pool is not heatedNatural gas onlyElectricity onlyElectric heat pump only

Solar heater (using solar collectors)Bottled gas only (propane, butane, LP)Other

(PG&E-3)

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J5 Please indicate how often you heat your pool in the summer and winter.Summer (May – Oct.) Winter (Nov. – April)

Morning(6am-10am)

Mid-Day(10am-6pm)

Night(6pm-6am)

Morning(6am-10am)

Mid-Day(10am-6pm)

Night(6pm-6am)

NeverOnce a monthOnce a week2 – 4 times per weekKeep pool heated continuously

J6 What type of filtration pump does your pool have? Single speed Two speed Variable speed No filtration pump

J7 Which of the following attributes does your pool have? (Choose all that apply.)Cover Pool timer Pool sweep Pool vacuum Pool is indoors

Entertainment and Technology K1 How many televisions and accessories do you use in this home?

Televisions: None 1 2 3 or moreOLED (organic light-emitting diode) or LED TV(s):…………………………………smaller than 36 inches……………………between 36 inches and 59 inches

………………………………… 60 inches or largerLCD (liquid crystal display) TV(s):…………………………………smaller than 36 inches……………………between 36 inches and 59 inches………………………………… …60 inches or larger

Plasma display panel TV(s)Cathode ray tube TV(s) (CRT, tube style)DLP or rear-projection TV(s)Accessories:Cable or satellite TV set-top boxes or receivers, DVRStand-alone movie players (Blu-Ray/DVD/VCR)Gaming systems (Nintendo, PlayStation, Xbox, Wii)Streaming media players (Amazon Fire Stick,

AppleTV, Chromecast, Roku)Home Theater system connected to TVSoundbar connected to TVSeparate sound or stereo system connected to TVStand-alone stereo, iPod or MP3 docking station

K2 How many combined total hours are your televisions on each day? (Add up time for all TVs. Example: 13 hours a day for one + 16 for another equals 29 total hours.)

1 houror less

1 – 8hours

9 – 16 hours

17 – 24hours

25 – 30 hours

Over 30hours

TVs smaller than 36 inchesTVs 36 inches to 59 inchesTVs 60 inches or larger

(PG&E-3)

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K3 How many personal computer(s) (PC, Apple, etc.) do you use in this home? None 1 2 3 or more

Desktop(s)Laptop(s)

K4 If you have one or more computer(s) in this home, how many combined total hours are they turned on each day? (Add up time for all computers, including stand-by)

1 houror less

1 – 8hours

9 – 16hours

17 – 24hours

25 – 30 hours

Over 30 hours

Desktop(s)

Laptop(s)

K5 Do you or someone else in your home operate a business and/or work from your home?

No (Go to K7.) Yes K6 How many hours a week is someone working out of your home?

0 – 10 hours per week 11 – 30 hours per week More than 30 hours per week

K7 How many of the following products do you use in this home?None One Two Three or more

Printer, Scanner, Copier or Multifunction machineTablet computer or e-reader (iPad or Kindle)Hubs, controllers, smart speaker (Amazon Echo,

Google Home, Apple HomePod)Smart home devices (other than lighting)“Smart” cell phone (iPhone or Android)Other cell phone (flip phone, candy bar phone)High-speed modem for Internet(DSL/cable/satellite)Home network (wired or wireless)Uninterrupted Power Supply (UPS, power backup)

Lighting L1 What portion of light bulbs installed in the ceiling fixtures and lamps inside your

home are the following types? (Choose one answer for each type.)Classic glass bulb above the metal screw base

“Twisty” tube can be coveredShort plastic base

Spherical glass coverLarge plastic base

Incandescent CFL LED

Lamp or Bulb TypeNone Some About

half Most All

Incandescent (traditional light bulbs that have been around for 100 years)

CFLs, Compact fluorescent (sometimes have a “twisty”, spiral shape, but the “twisty” can be covered in opaque glass)

LED, Light emitting diodes (newest bulbs on the market, often with a large plastic base sometimes with ridges)

(PG&E-3)

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L2 How many lights inside your home are turned on during the following times of day?(Choose one answer for each time period.)

Time PeriodNone Few lights

(about 25%)Some lights(about 50%)

Many lights (about 75%)

All lights (100%)

Morning (6am-9am)Day (9am–5pm)Evening (5pm–9pm)Night (9pm–6am)

L3 How many of the following lighting products do you use inside your home?Interior Lighting Products None 1 – 2 3 – 5 6 – 10 11 or MoreFixtures on timers Fixtures on motion detectors or occupancy sensorsFixtures on a dimming switch“Smart” (connected) light bulbsNightlights

L4 How many of the following lighting products do you use outside your home?(Include items in your garage. Only include exterior lights that are paid for on your electricity bill.)Exterior Fixtures None 1 – 2 3 – 5 6 or MoreExterior incandescent fixturesExterior compact fluorescent fixturesExterior light-emitting diode (LED) fixturesLow voltage landscape light systemHID (sodium vapor, metal halide) fixture

Exterior Lighting Controls None 1 – 2 3 – 5 6 or MoreFixtures on timersFixtures on dusk-to-dawn sensorsFixtures on motion detectors

Miscellaneous AppliancesM1 How many of each of the following appliances or equipment do you use in your

home? (Choose all that apply.)None 1 2 3 or More

Chargers left plugged in all the time (phone/tablet/tools)Rechargeable vacuum (Roomba, RoboVac, Botvac)Small cooking (air fryer, Instant Pot, slow cooker)Portable fanCeiling fanWind turbine attic ventilator (non-electric)Electric attic fanWhole-house fanElectronic household air cleanerPortable (room) air purifierHumidifier or dehumidifierWine or beverage coolerWater purification systemDomestic hot water recirculation pumpSauna – electricPond or water garden pump or fountainOutdoor fire table/fire pit

(PG&E-3)

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M2 Do you use an electric well water pump to provide water for your home?No (Go to M5.)Yes M3 Does your home also have access to city/county water

sources? Yes No M4 How do you use your well water?

Only for gardening and landscaping Only for household use Both household and gardening/landscape use

M5 Select fuel type for any of the equipment that is used three or more hours per week

Electric Natural Gas Bottled GasSump pumpShop toolsElectric welding equipmentElectric air compressorCharger for large batteryKiln for ceramics and potteryMedical equipment (e.g., respirator)

M6 Do you have an electric bicycle, skateboard, wheelchair, or golf cart at your home?No (Go to M8.)Yes, electric wheelchair/cartYes, electric bicycle/skateboard

M7 Do you charge your electric wheelchair, cart, skateboard or bicycle at home?

Yes No

M8 Do you use any other equipment or large appliance that consumes a significant amount of electricity or natural gas in your home?

No Yes (Please describe equipment and fuel.):___________________

M9 Please indicate if you have added or replaced any of the following appliances in the past 12 months. If the new item replaced an existing unit, please be sure to answer question M10 as well. (Choose all that apply.)

Added Fuel Type of New UnitAppliance a New Unit Elec Natural Gas Other

Central heating Central cooling Wall or window air conditionerEvaporative (swamp ) coolerWater heaterRefrigeratorStand-alone freezerStove topOvenMicrowave ovenDishwasherClothes washerClothes dryerPool heaterPool pumpHot tub/spa heater

Have not added or replaced any of the above appliances.

(PG&E-3)

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M10 Please indicate if you have discarded any of the following appliances in the past 12 months. Include both items that were replaced and those that were discarded without being replaced. (Choose all that apply.)

Age of Discarded Unit Fuel Type of Discarded Unit

Appliance1–10years

11–20years

Over 20years Elec

NaturalGas Other

Central heating Central cooling Wall or window air conditionerEvaporative (swamp)coolerWater heaterRefrigeratorStand-alone freezerStove topOvenMicrowave ovenDishwasherClothes washerClothes dryerPool heaterPool pumpHot tub/spa heater

Have not discarded any of the above appliances.

Renewable Energy TechnologiesM11 Which of the following renewable energy technologies are currently used at this

residence? (Check all that apply.)No renewable energy technologiesSolar electricity/photovoltaic (PV) cellsSolar water heating (In-home water heated)Battery storage connected to solarWind generatorFuel cells

M12 In the next two years, do you plan to install any of the following renewable technologies? (Check all that apply.)

No plansSolar electricity/photovoltaic (PV) cellsSolar domestic water heating (In-home water heated)Solar pool water heating (Pool water heated)Battery storage connected to solarWind generatorFuel cellsOther: (describe)_____________________________

(PG&E-3)

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Household InformationPlease provide answers to the following questions. Your responses will be confidentialand no data will be used on an individual basis. The information is used to allow us to compare energy usage between various groups.

N1 In addition to the home described in this survey, do you own any other home in California that is occupied on a part-time basis by your family or as a vacation rental? (Please do not answer yes for any full-time rental property or time-share units.)

Yes No (Go to N3.)

N2 Please provide the following information for your seasonal or vacation home that you own in California? (Please do not provide information for the home described in this survey, any full-time rental property or any time-share units.)Location In the mountains Near the ocean

In the desert OtherNear a lake or river

Electricity is provided to this vacation home by:

PG&E LADWPSCE SMUD SDG&E Other

Natural gas is provided tothis vacation home by:

PG&E SoCalGas NoneSDG&E Other

N3 What was the highest level of education completed by any head of household in the home?

Elementary (grades 1 – 8)Some high school (grades 9 – 12)High school graduate

Some college/trade/vocational schoolCollege graduatePostgraduate degree

N4 What is the primary language spoken in this home?EnglishAsian/Pacific Island (describe)_____________

SpanishOther (describe)_______________

N5 Are any of the occupants of your home permanently disabled?No Yes, 1 permanently disabled Yes, 2 or more permanently disabled

N6 Which of the following ethnic groups are represented by your head(s) of household? (Choose all that apply.)

Head of Household # 1 Head of Household # 2American Indian, Alaska NativeAsian or Pacific IslanderBlack, African AmericanHispanic / LatinoWhite, CaucasianOther

N7 Please check the range that best describes your household’s total annual income.

Less than $10,000 $50,000 – $74,999 $175,000 – $199,999$10,000 – $19,999 $75,000 – $99,999 $200,000 – $249,999$20,000 – $24,999 $100,000 – $149,999 $250,000 or more$25,000 – $49,999 $150,000 – $174,999 Prefer not to answer

(PG&E-3)

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Please return your survey in the enclosed envelope. The sponsors are grateful for your time and input.

Thank you very much for participating!Frequently Asked Questions -

What is the California Home Energy Survey? The California Home Energy Survey is a comprehensive study of residential energy use. The survey asks households to provide information on appliances, equipment, and general energy use. The survey is conducted periodically, with two previous studies completed in 2009 and 2003.

Who is the sponsor of the California Home Energy Survey? The California Home Energy Survey is sponsored by the California Energy Commission and the following utilities: Pacific Gas and Electric Company (PG&E), Southern California Edison (SCE), San Diego Gas & Electric Company (SDG&E), Southern California Gas Company (SoCalGas), Sacramento Municipal Utility District (SMUD), and the Los Angeles Department of Water and Power (LADWP). The sponsoring organizations have teamed up to conduct a common study, provide a central set of information to guide state-wide energy planning and minimize study costs.

How can I confirm the California Energy Commission sponsors the study? The Commission provides more information about this survey on their official website at: www.energy.ca.gov/appliances/rass. Final reports from the 2009 and 2003 studies are also available to download from this website.

Where can I get help to complete this survey? DNV GL Energy Insights USA, Inc. has been hired by the California Energy Commission to manage this study. Contact the DNV GL survey support team by emailing them at: support@calhes.dnvgl.com or calling them on the toll-free line at 1 (866) 363-7448. DNV GL representatives are available to answer questions about this survey Monday through Friday, 8:30 a.m. to 5:00 p.m. Pacific Daylight Time.

What if I don’t know the answer to some of the questions? Do your best to answer all of the questions. If you do not know the answer to a question, just move on to the next one. Please answer the questions as they pertain to your residence or unit only.

Will the California Energy Commission keep my information confidential? Yes. To protect your privacy a unique ID was assigned to your household. Survey results are reported in anonymous or summary form and will not reveal individual identities.

Why does my response matter to the California Energy Commission? The more people that complete their surveys, the better that we can plan for future energy needs in California. It is important that we get an up-to-date picture of how California uses energy so that we can ensure that there is adequate energy available to meet California’s future needs.

How do I benefit by answering the California Home Energy Survey? Your participation supports state-wide planning activities that help your community, and the information you collect can reveal potential energy improvements in your own household.

(PG&E-3)

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