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Application: 16-06-013 U 39 M Exhibit No.: (PG&E 53) Date: March 16, 2018 Witness(es): Various
PACIFIC GAS AND ELECTRIC COMPANY
2017 GENERAL RATE CASE PHASE II
AGRICULTURE RATE DESIGN
REBUTTAL TESTIMONY
(PG&E-53)
PACIFIC GAS AND ELECTRIC COMPANY
REBUTTAL TESTIMONY ON
AGRICULTURAL RATE DESIGN ISSUES
(PG&E-53)
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PACIFIC GAS AND ELECTRIC COMPANY REBUTTAL TESTIMONY ON
AGRICULTURAL RATE DESIGN ISSUES
TABLE OF CONTENTS
A. Introduction .......................................................................................................... 1
B. Proposed Rates ................................................................................................... 4
C. Proposed Modifications to Existing Initiatives ...................................................... 8
D. Transition Timing, Customer Education and Outreach and Customer Tools .................................................................................................................. 10
E. Rate Changes Between GRCs .......................................................................... 14
F. Grandfathered TOU Periods for Solar Customers ............................................. 16
G. Conclusion ......................................................................................................... 16
Appendix A – Illustrative Proposed Rates – Rate Schedules AG-A, AG-B, AG-C and AG-R
Appendix B – Illustrative Bill Impacts of Present Versus Proposed Total Rates
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PACIFIC GAS AND ELECTRIC COMPANY 1
REBUTTAL TESTIMONY ON 2
AGRICULTURAL RATE DESIGN ISSUES 3
A. Introduction 4
Q 1 Please state your name and the purpose of this rebuttal testimony. 5
A 1 My name is Keith Coyne. This testimony responds to the direct testimony of 6
California Farm Bureau Federation (CFBF) and the Agricultural Energy 7
Consumers Association (AECA) (the Agricultural (Ag) Parties) regarding 8
agricultural rate design. By email ruling of Administrative Law Judge 9
Doherty dated February 28, 2018, Pacific Gas and Electric Company 10
(PG&E) and the Ag Parties were granted an extension of time to serve 11
rebuttal from March 7, 2018, to March 16, 2018. 12
I am sponsoring Sections A, B, C, E and G of this rebuttal. Section D is 13
sponsored by Emily Bartman and Section F is sponsored by Tysen Streib. 14
Q 2 Describe the Opening Testimony of AECA and CFBF with regard to 15
agricultural rate design. 16
A 2 CFBF provided rate design testimony in the Opening Testimony of 17
Ryan Jacobsen and the Opening Testimony of Laura Norin and 18
Brandon Charles, both dated March 15, 2017. CFBF’s rate design 19
recommendations are provided in the Opening Testimony of Laura Norin 20
and Brandon Charles.1 In the following rebuttal testimony, PG&E 21
references each of CFBF’s rate design proposals as PG&E’s proposed rate 22
design is discussed. PG&E agrees with a number of CFBF’s rate design 23
recommendations. However, in Recommendation 2, CFBF recommends 24
that a mandatory change to TOU periods be deferred until new TOU periods 25
can be re-evaluated. CFBF Recommendation 2 is provided below. 26
(2) Any new TOU periods adopted in this proceeding should be 27 implemented on an optional, not mandatory, basis until new TOU 28 periods can be re-evaluated with 1) full consideration given to time-29 differentiation of transmission and distribution costs and 2) better data 30 available on market transition issues, including electric vehicle adoption 31 rates, and charging load shapes, energy storage deployment, CCA 32 formation, and Diablo Canyon replacement power. In the meantime, 33 PG&E should offer customers several TOU period definition options in 34
1 See Summary of Recommendations, pages 58-61.
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order to reflect the uncertainty inherent in current and future market 1 conditions and to be consistent with Commission rate design principles 2 concerning customer choice and customer acceptance. Reasonable 3 options include the current TOU periods, flat rates, and any TOU period 4 proposal that is adopted in this proceeding. 5
AECA provided rate design testimony in the Opening Testimony of 6
Richard McCann dated March 15, 2017. AECA summarizes its rate design 7
recommendations on pages 40 and 41 of that testimony. Like CFBF, 8
AECA’s recommendations include some detailed recommendations on rate 9
design (including proposals for rate options),2 as well as a proposal that 10
would allow customers to take service on the current Time-of-Use (TOU) 11
periods for a number of years. AECA’s Recommendation 1 is provided 12
below. 13
1. Agricultural customers should be offered grandfathered TOU periods 14 for up to 10 years to allow them to recover investments that benefited all 15 ratepayers through peak shifting. 16
Q 3 As discussed above, CFBF recommends that new TOU periods should be 17
re-evaluated at a future time before they are implemented on a mandatory 18
basis. In addition, CFBF also proposes that the new TOU periods do not 19
become mandatory until they are demonstrated to be workable for 20
agricultural customers in a manner that is consistent with water efficiency 21
practices (CFBF Opening Testimony, p. 61). Do you agree with CFBF’s 22
proposals? 23
A 3 No. PG&E believes that the California Public Utilities Commission (CPUC or 24
Commission) should establish optional rates along with the ultimate 25
mandatory rate structure and TOU periods in this proceeding. Generation 26
costs have already shifted and are reflected in the TOU periods proposed by 27
PG&E, which have also been adopted in Decision (D.) 15-11-013 and 28
settled in the recently filed Small Light and Power (SL&P) and Medium and 29
Large Light and Power (MLL&P) settlement agreements for commercial and 30
industrial customers. There is no reason to delay introduction of accurate, 31
2 AECA Opening Testimony, page 40 and 41. AECA recommendations: (4) PG&E
should offer a Real-Time Pricing tariff similar to that provided by SCE, which reflects dynamic rates while giving agricultural customers enough lead time to manage their loads; (5) PG&E should offer a Renewable Integration Rate tariff to enable agricultural customers to manage their loads in ways that help integrate the grid’s growing share of renewables; and (6) PG&E should implement a virtual load aggregation program.
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cost-based, TOU periods for agricultural customers on an opt-in basis rather 1
than implementing the change as soon as possible, with appropriate 2
outreach, to enable the transition of as many customers as possible to rates 3
with accurate price signals. PG&E does not propose mandatory 4
implementation of new TOU periods for agricultural customers until 5
March 2021, at the earliest, to provide time for agricultural customers to 6
evaluate the new rate structures and develop and implement plans to 7
transition their operations to the new time periods. PG&E believes that 8
further delay would be contrary to Commission direction in the TOU Order 9
Instituting Rulemaking and would needlessly shift costs from agricultural 10
customers to others. PG&E intends that the new proposed rates with new 11
TOU periods be available to agricultural customers on an opt-in basis at 12
least 12 months prior to the time when they become mandatory.3 13
Q 4 AECA requests that grandfathered TOU periods be available to agricultural 14
customers for up to 10 years. In addition, AECA recommends that a 15
number of optional rates be made available. Do you agree? 16
A 4 No. PG&E does not believe that rates with grandfathered TOU periods 17
should be provided to all agricultural customers. However, PG&E believes 18
investigation is warranted to determine if additional mitigation is required for 19
mandatory transition to new TOU periods for non-solar agricultural 20
customers.4,5 Paragraphs 7 and 8 of Appendix 1 of D.17-01-006 21
3 This timeline comports with PG&E’s proposed timeline, but provides a slightly longer
period when the rates with new TOU periods would be available on an opt-in basis. In Exhibit (PG&E-8), Volume 1, Chapter 10, pp. 10-22 to 10-27, PG&E proposed that: (1) rates with new TOU periods will be implemented on a voluntary basis 9 to 12 months following a decision in this proceeding; and (2) those voluntary rates will become mandatory six to nine months after they are offered on a voluntary basis.
4 PG&E’s proposed illustrative rates are provided in Appendix A, and bill comparison results are provided in Appendix B.
5 For example, ‘Each IOU should take steps to minimize the impact of TOU peak period changes on customers who have invested in on-site renewable generation or technology to conserve energy during peak periods..... Additional steps to increase certainty around TOU periods could include vintaging, legacy TOU periods, or fixed indifference payments, as well as other rate structures that provide predetermined limits on TOU period changes…Also, IOUs are encouraged to use the Base TOU periods to develop at least one optional TOU rate design with a more complex combination of season and time period and may incorporate more dynamic pricing features and enabling technology as appropriate to address grid needs.’ (D.17-01-006, p. 8.)
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recommends each IOU take appropriate steps to minimize the impact of the 1
change to new TOU periods. While PG&E’s proposal provides optional 2
rates with alternative base TOU periods consistent with the directives of 3
D.17-01-006 (i.e., the new AG-R, and a choice for larger customers between 4
Schedules AG-B and AG-C), additional review may be appropriate in 5
connection with the most impacted agricultural customers. 6
Q 5 When would PG&E conduct that review and provide any necessary 7
additional mitigations to the Commission for approval? 8
A 5 PG&E proposes to provide a proposal for any additional mitigation in its 9
2019 Rate Design Window (RDW) proceeding which would be filed by 10
November 25 of this year (2018). Utilizing the 2019 RDW proceeding will 11
provide the time necessary for PG&E to further evaluate the need for 12
mitigation and determine appropriate additional rate options and mitigations. 13
Moreover, determining the need for additional rate options and mitigation in 14
the 2019 RDW should yield a decision on any necessary changes prior to 15
the proposed March 2021 date for the new mandatory agricultural 16
TOU rates. 17
B. Proposed Rates 18
Q 6 Please describe PG&E’s proposal with regard to the current rate structures. 19
A 6 PG&E proposes to retain rate schedules with the current TOU periods and 20
structures (the “legacy rate schedules”) until rates with new TOU periods 21
become mandatory. When the revenue allocation set forth in the Marginal 22
Cost and Revenue Allocation (MC/RA) Settlement Agreement is 23
implemented (as expected in January 2019), agricultural rates with new 24
TOU periods will not yet be available. Accordingly, the rates for the legacy 25
rate schedules will be calculated consistent with the revenue allocation set 26
forth in Tables 1 and 2 of the MC/RA Settlement Agreement, based on 27
March 1, 2017 effective rates. Rate design that will govern changes to 28
these legacy rates when the MC/RA Settlement Agreement is implemented, 29
and when legacy rates are updated prospectively for revenue requirement 30
and sales changes, will be consistent with the rules for rate changes set 31
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forth in the MC/RA Settlement Agreement and in Section E below.6 PG&E’s 1
proposals for changes to these legacy rates are designed to minimize 2
changes to the structure of these rates. 3
When rates with new TOU periods are implemented on an opt-in basis, 4
the legacy rates will be closed, including new customer enrollment and any 5
customer transfers between agricultural rate schedules. Also, effective with 6
the availability of rates with new TOU periods, demand billing on legacy 7
Schedules AG-1A, AG-4A, AG-VA, AG-RA and AG-5A will be converted 8
from connected load to metered demand.7 9
Q 7 Please describe PG&E’s proposed rates which would be available for an 10
opt-in period before becoming mandatory in 2021. 11
A 7 The most significant change PG&E is making to its originally filed 12
agricultural rate design proposal is to change the original TOU period 13
proposal with a peak period from 5 p.m. – 10 p.m., to a mandatory TOU 14
period for agricultural customers with a peak from 5 p.m. – 8 p.m. This 15
revised peak period falls squarely in the middle of the currently proposed 16
peak period for commercial and industrial customers (4 p.m. – 9 p.m.), and 17
addresses operational constraints raised by CFBF8 by ending the peak 18
period at the earliest possible time consistent with sending appropriate price 19
signals. This shorter peak period is consistent within the broad direction set 20
forth in D.17-01-006 as described previously. The proposed seasons and 21
TOU periods for Schedules AG-A, AG-B and AG-C used to derive illustrative 22
rates set forth in Appendix A are: 23
• Summer: June through September (4 months) 24
• Winter: October through May (8 months) 25
6 At the time that rates with new TOU periods become mandatory, the legacy TOU
schedules (AG-4, AG-5, AG-R, AG-V and AG-R) will be retained to satisfy the requirement to continue rates with the current TOU periods for solar customers as directed by D.17-01-006.
7 PG&E agrees with CFBF Recommendation 9 “PG&E’s proposal to apply only limited adjustments to the legacy agricultural rate schedules should be adopted, with two exceptions: (i) PG&E’s proposal to increase customer charges on those rate schedules should be rejected, and (ii) customers on legacy AG-A schedules with interval meters should be shifted to be billed on a metered kWh basis instead of a connected load charge basis.” In Section E below, PG&E agrees to hold the customer charges on legacy rates at their current level.
8 See Testimony of Ryan Jacobsen on Behalf of CFBF, dated March 15, 2017, pp. 4-5.
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• Peak Period: 5 pm to 8 pm, all days of the year 1
• Off Peak Period: All remaining hours 2
In addition, Appendix A includes customer charges as proposed by 3
PG&E. PG&E has proposed new customer charges for Schedules AG-A, 4
AG-B and AG-C and has applied those same customer charges to the new 5
AG-R rate. Application of PG&E’s proposed customer charges results in 6
some customer charges increasing and others decreasing. AECA and 7
CFBF disagree with PG&E proposed customer charges.9 PG&E believes its 8
proposed customer charges are reasonable and should be adopted. 9
PG&E’s proposed customer charges generally represent a 20 percent 10
increase over the current charges applicable on most legacy agricultural rate 11
schedules, and are designed to move in a moderate manner toward cost 12
based levels. 13
Consistent with its initial proposal in this proceeding, PG&E continues to 14
propose demand billing for Schedule AG-A be based on metered demand 15
rather than connected load. In addition, PG&E proposes a demand charge 16
limiter (DCL) for customers served under Schedule AG-C which will govern 17
average rate levels (excluding the fixed monthly customer charge). The 18
DCL will be equal to 50 cents per kilowatt-hour (kWh) and will apply to both 19
summer and winter bills. Shortfall from the DCL will be estimated and 20
applied to increase distribution energy charges on Schedule AG-C. Finally, 21
as initially proposed, the Optimal Billing Period Program will be retained for 22
customers served on new Schedule AG-C.10 23
9 CFBF Recommendation 7: “PG&E’s proposed increases in agricultural customer
charges should be rejected, and the current customer charges should be maintained throughout the GRC cycle.” AECA Recommendation 2: “Customer charges should be held constant at current levels, as many other rate elements are changing, and PG&E’s marginal costs used for EPMC scaling are questionable. PG&E has proposed new customer charges for Schedules AG-A, AG-B and AG-C and has applied those same customer charges to the new AG-R rate. Application of PG&E’s proposed customer charges results in some customer charge levels increasing and others decreasing.”
10 PG&E is in agreement with CFBF Recommendations 5, 6 and 8, page 59. 5: “PG&E’s proposed $0.50 per kWh demand charge limiter should be adopted for AG-C customers; no demand charge limiter should be adopted for AG-A or AG-B customers.” 6: “PG&E’s proposal to implement an “Optimal Billing Period” for AG-C customers and to maintain the Optimal Billing for AG-5C customers until that rate schedule is eliminated should be adopted.” 8: “PG&E’s proposal to bill all customers with interval meters on an actual metered kW basis should be adopted.”
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In addition, PG&E proposes a new Schedule AG-R. Schedule AG-R will 1
have three options consistent with the primary schedules: AG-RA, AG-RB 2
and AG-RC. Illustrative rates for Schedule AG-R were not provided with 3
initial testimony but are now provided in Appendix A.11 Schedule AG-R 4
would have a 4-month summer season and peak hours of 5 p.m. to 8 p.m. 5
consistent with the AG-A, AG-B and AG-C rates, and would provide similar 6
pumping flexibility and long off-peak pumping hour periods compared to the 7
legacy Schedule AG-R. The new Schedule AG-R includes three options for 8
off peak periods (that is, no peak period on these days), specifically for the 9
days noted as follows: 10
1) Group 1 is the two-consecutive 100 percent off-peak weekdays of 11
Wednesday and Thursday; 12
2) Group 2 is the two-consecutive 100 percent off-peak weekend days of 13
Saturday and Sunday; and 14
3) Group 3 is the two-single 100 percent off-peak days that are separated 15
by four days within the same calendar week of Monday and Friday.12 16
These three Groups as specified above provide for six non-overlapping 17
100 percent off-peak days to better stagger agricultural loads throughout the 18
week. PG&E will work with customers who elect AG-R in a local circuit area 19
to place customers in different groups to stagger loads to avoid creating or 20
aggravating local electric system constraints, and to mitigate overlapping 21
pumping operations that could otherwise aggravate local ground water 22
11 CFBF Recommendation 4: “PG&E’s assumptions and processes used to develop the
sample AG-R rates provided in Table 6 should be adopted along with the relationships between AG-A, AG-B and AG-C rates and the AG-R rates that are shown in PG&E’s sample rates.” PG&E’s illustrative rates reflect somewhat different relationships that shown in CFBF’s Table 6. Illustrative rates for AG-A, AG-B, AG-C and AG-R have since been revised to reflect more current rates, and revised TOU periods. PG&E’s proposed AG-R rates are, however, designed to provide relationships that are consistent with Schedules AG-A, AG-B and AG-C.
12 CFBF Recommendation 3, page 59, and AECA Recommendation 7, page 41, both suggest a larger number of ‘off peak days.’ PG&E is not focused on a specific number, but prefers to offer a discrete set of ‘off peak days’. CFBF Recommendation 3: “PG&E’s proposed new AG-R rate schedule should be further expanded such that the off-peak periods could be any two consecutive days of the week, with PG&E determining which off-peak days should be available to any given customer based on the load characteristics on the local circuit.” AECA Recommendation 7: “The revised AG-R rate should offer combinations of all two-day off peak periods that cover all days of the week.”
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pumping and pumping efficiency or equipment concerns. PG&E will have 1
the final authority to designate customers in each group to accommodate 2
these objectives, but will seek to accommodate customer operational 3
efficiency goals and convenience to the greatest extent possible. 4
Customers must opt in to this new rate schedule (i.e., customers will be 5
assigned to AG-A, AG-B or AG-C based on a pre-determined 6
standard default rate, subject to their choice of an otherwise applicable 7
rate schedule). 8
Q 8 Were there additional rate design proposals that were not accommodated by 9
PG&E’s proposed rates? 10
A 8 Yes. AECA has proposed to use daily demand charges.13 PG&E opposes 11
daily demand charges because they fail to hold customers properly 12
accountable for their cost imposition upon the PG&E system, which must be 13
built as a general rule to meet the single annual maximum peak demand 14
that a customer may impose. Daily demand charges would also greatly 15
complicate billing, and may inequitably shift costs across customers of 16
differing load factors or costs of service. 17
C. Proposed Modifications to Existing Initiatives 18
Q 9 Does PG&E propose to modify any current initiatives because of the 19
transition to new TOU periods? 20
A 9 Yes. PG&E proposes to suspend the ongoing mandatory transition of 21
customers to the current TOU periods; as well as the requirement to default 22
customers to Peak Day Pricing (PDP). Similar initiatives are included in the 23
SL&P, and Standby and MLL&P Rate Design Settlement Agreements. 24
Q 10 What does PG&E propose with regard to the mandatory transition of 25
customers to TOU rates? 26
A 10 Each year, PG&E migrates bundled customers that take service on the non-27
TOU Schedule AG-1 to Schedule AG-4 (or alternatively, the customer can 28
select an otherwise applicable TOU rate). The transition occurs on a billing 29
serial basis beginning on March 1st of each year, for eligible agricultural 30
customers with 12 months of interval data. Beginning on March 1, 2019, 31
13 AECA Recommendation 3: “Agricultural demand charges should be set and billed on a
daily basis to better reflect true cost causality, and provide a price incentive to growers to manage coinciding pumping loads.”
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this transition process should be suspended until rates with new TOU 1
periods become mandatory for agricultural customers to avoid transition to 2
outdated TOU periods.14 PG&E will resume the transition process for 3
bundled customers with 12 months of interval data that take service on 4
Schedule AG-1 to rates with new TOU periods when those rates become 5
mandatory. PG&E will also begin the transition process for customers 6
served under Direct Access and Community Choice Aggregation (CCA) with 7
12 months of interval data that take service on Schedule AG-1 to rates with 8
new TOU periods when those rates become mandatory. 9
Q 11 What does PG&E propose with regard to PDP? 10
A 11 Each year, PG&E defaults eligible customers to PDP, provided each 11
customer may opt out of PDP to take service on a TOU rate. The transition 12
occurs on a billing serial basis beginning on March 1 of each year, for 13
eligible agricultural customers with 12 months of interval data and 14
24 months on TOU service. Beginning March 1, 2019, PG&E proposes to 15
suspend this default PDP process until rates with new TOU periods become 16
mandatory for agricultural customers. PG&E will retain PDP on an opt-in 17
basis with the current PDP hours for customers that continue to take service 18
on the legacy rates until the rates with new TOU periods become 19
mandatory. PDP will not be available on the rates with new TOU periods 20
while those rates are available on an opt-in basis. Accordingly, customers 21
who opt in to the new TOU hours while rates with new TOU periods are 22
available on an opt-in basis, must un-enroll from PDP. 23
14 On November 21, 2017, PG&E filed a Petition to Modify D.10-02-032 and D.11-11-008
to suspend transition to mandatory TOU and default to PDP for agricultural customers that would have occurred on March 1, 2018. The Executive Director approved the suspension on an interim basis while the Commission considers the Petition to Modify. While the transition to TOU applies to all agricultural customers, default PDP in the agricultural sector applies only to large agricultural customers over 200 kilowatt (kW). Agricultural customers under 200 kW may opt-in to PDP.
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New PDP event hours must be approved by the Commission by the time 1
the new TOU periods adopted in this proceeding become mandatory so that 2
PDP can be offered with the rates with new TOU periods. PG&E proposes 3
to have the same event period apply to both the SmartRate™15 and PDP 4
programs. PG&E further proposes to request alignment of event periods for 5
the programs by advice letter once a decision is issued on the event periods 6
for SmartRate. PG&E will follow the process set forth in the SL&P and 7
Standby and MLL&P Rate Design Settlement Agreements to seek that 8
alignment. In those Settlement Agreements, PDP event periods of 9
5 p.m. – 8 p.m. may be put into place on a permanent basis via advice letter 10
if the Commission approves SmartRate event periods of 5 p.m. – 8 p.m. in 11
the 2018 RDW. Alternatively, PDP event periods of 5 p.m. – 8 p.m. could be 12
implemented on a temporary basis subject to final approval of PDP event 13
periods in either the 2019 RDW or 2020 General Rate Case (GRC) Phase II 14
proceedings, where revisions to the PDP program may be addressed 15
without limitation. PG&E would resume defaulting eligible agricultural 16
customers to PDP, provided each customer may opt out of PDP to take 17
service on a TOU rate, when the rates with new TOU periods are mandatory 18
and PDP is available on those schedules. 19
Finally, PG&E proposes to continue the annual adjustment to the PDP 20
revenue neutral credits, together with the direct assignment of costs to each 21
schedule for bill protection and the adjustment for the number of events per 22
year (when the number of events is more or less than the design basis). 23
D. Transition Timing, Customer Education and Outreach and Customer Tools 24
Q 12 Does PG&E agree with CFBF’s assertion that PG&E’s proposed mandatory 25
implementation of new TOU periods would happen as early as 15 months 26
after a decision in this proceeding? 27
15 SmartRate is the critical peak pricing program for residential customers. PG&E has
proposed to change the SmartRate event hours to 5 p.m. – 8 p.m. in PG&E’s 2018 RDW proceeding.
The name SmartRate is a registered trademark of PG&E. All further references to the program in PG&E’s testimony in this proceeding should be assumed to refer to the trademarked name, without continually using the ™ symbol, consistent with legally-acceptable practice.
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A 12 PG&E disagrees that the proposed timeline for mandatory implementation of 1
new TOU periods for agricultural customers would be as early as 15 months 2
after a decision in this proceeding, given the current expected decision in 3
August 2018, and further internal implementation planning. CFBF states 4
correctly that PG&E’s initial proposal was that rates with the new 5
TOU periods would be available optionally as early as nine months after a 6
decision, and would become mandatory six months later at the earliest, 7
potentially 15 months after a decision. However, PG&E also proposed that 8
the agricultural transition occur in March to align with the current TOU/PDP 9
program transition timing. Assuming a decision on agricultural rate design 10
issues in August 2018, and updated implementation planning, the new 11
optional rates would be available by March 2020. PG&E also agrees that 12
the mandatory transition to rates with the updated TOU periods can be 13
delayed until March 2021, which would allow 31 months before the new 14
TOU periods become mandatory, more than twice the 15 months 15
originally proposed. 16
Q 13 Does PG&E believe the current proposed mandatory implementation of 17
new TOU periods 31 months after a decision in this case is unnecessarily 18
abrupt? 19
A 13 PG&E believes that 31 months is sufficient time for agricultural customers to 20
prepare for mandatory rates with appropriate TOU periods. In addition, this 21
case was filed in June of 2016, and new mandatory rates with updated TOU 22
periods in March 2021 would result in almost five years of lead time from the 23
time the case was filed, when it was established that the current TOU 24
periods are very mis-aligned with generation costs and are sending 25
inappropriate price signals which encourage customers to use electricity 26
when the costs are the highest, and to reduce usage when costs are lower, 27
thus raising costs for all customers. 28
Q 14 Does PG&E agree with CFBF that additional time for education and 29
outreach is needed, given specific challenges for agricultural customers?16 30
A 14 Yes, PG&E agrees with CFBF that more time than PG&E originally 31
proposed is needed for agricultural customers. As explained above, PG&E 32
16 CFBF recommendation 11a, p. 61.
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agrees to extend the implementation of mandatory rates with new TOU 1
periods until March 2021, which enables at least 12 months for education 2
and outreach and is 3 to 6 months more than originally proposed. 3
Q 15 Does PG&E believe any agricultural customers should remain on their 4
current rate schedule with outdated TOU periods unless they opt-in to a rate 5
with the new TOU periods?17 6
A 15 PG&E believes it is critical for customers to begin migration to the correct 7
TOU periods as soon as possible, and all agricultural customers that have 8
not opted in to the new TOU periods should be defaulted in March 2021, 9
unless eligible for grandfathered TOU periods for solar customers. TOU 10
periods are very far away from aligning with generation costs and are 11
sending inappropriate price signals which encourage customers to use 12
electricity when the costs are the highest, and to reduce usage when the 13
costs are lower, thus raising costs for all customers. Assuming a decision in 14
late 2018 and mandatory default in March 2021, agricultural customers will 15
have more than two years to prepare for new mandatory TOU periods. 16
Q 16 How does PG&E plan to address CFBF’s desire for agricultural customers to 17
understand the impending rate changes and develop workable strategies to 18
minimize bill increases prior to rates with the new TOU periods becoming 19
mandatory? 20
A 16 PG&E will provide bundled estimated bills for each customer account under 21
then current legacy rates and rates with new TOU periods at least 22
12 months in advance of mandatory deployment, but no earlier than when 23
these rates are available on an opt-in basis. 24
PG&E will provide the following bundled rate analysis tools at least 25
12 months in advance of mandatory deployment, but no earlier than when 26
these rates are available on an opt-in basis. 27
– Rate and bill impact analyses of agricultural rate schedule options: 28
Provides (one) best eligible rate option at the service agreement level, 29
and includes the ability to compare several rate options at a time and to 30
evaluate the impacts of load and demand changes on bills. 31
17 CFBF recommendation 11c, p. 61.
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– Aggregation of service accounts to a customer level for the customer to 1
review: Identifies all the service agreements under a customer account 2
and indicates (for each service agreement under the customer account) 3
whether or not a better alternative rate option exists for a service 4
agreement, and includes a hot link to the analyses for those service 5
agreements. 6
– Customer-entered identifiers: Enables customer to easily see service 7
account relationships. 8
– Solar: Bill impacts and rate analyses for customers considering solar 9
and for existing solar customers. 10
PG&E will make available customer training and support to all 11
customers to assist them in using the rate analysis tools through in-person 12
meetings, webinars or similar interactive meeting opportunities. PG&E will 13
also identify and specifically target customers likely to be most impacted 14
with higher bills, with training and support, as well as offering mitigation that 15
can be developed in the 2019 RDW proceeding. 16
Q 17 Does PG&E agree with CFBF that customers on flat rates should remain on 17
flat rates until rates with the new TOU periods are ready? 18
A 17 PG&E agrees that transitions of customers from flat rates to TOU rates in 19
2018, 2019 and 2020 should be postponed until 2021, when rates with the 20
new TOU periods are mandatory.18 21
Q 18 Does PG&E agree that only flat rate customers should be transitioned to 22
rates with the new TOU periods as part of a pilot studies?19 23
A 18 PG&E disagrees that only flat rate customers should be transitioned to rates 24
with the new TOU periods as a pilot test before customers currently on the 25
outdated TOU periods are transitioned. As explained above, PG&E believes 26
that 31 months from a decision in this case is sufficient time for 27
agricultural customers to prepare for mandatory rates with appropriate TOU 28
periods. This case has established that the current TOU periods are very 29
18 On November 21, 2017, PG&E filed a Petition to Modify D.10-02-032 and D.11-11-008
to suspend transition to mandatory TOU and default to PDP for agricultural customers that would have occurred on March 1, 2018. The Executive Director approved the suspension on an interim basis while the Commission considers the Petition to Modify.
19 CFBF Recommendations 11(b) and 11(d), p. 61.
(PG&E-53)
-14-
far away from aligning with generation costs and are sending inappropriate 1
price signals which encourage customers to use electricity when the costs 2
are the highest, and to reduce usage when costs are lower, thus raising 3
costs for all customers. 4
E. Rate Changes Between GRCs 5
Q 19 What rules will PG&E employ to change rates between GRCs? 6
A 19 In general, total rates for the agricultural class change as the sum of the 7
individual components (e.g., distribution, generation, Public Purpose 8
Programs, etc.) change, where rules for each component are separately 9
stated. The rules for changing rates are set forth in the MC/RA Settlement 10
Agreement for all components of rates except for the generation and 11
distribution rates (see Section VIII, Part 3). Rate design rules for distribution 12
and generation were to be addressed for individual customer classes. 13
Accordingly, PG&E includes in this rebuttal testimony rate design rules for 14
distribution and generation for agricultural rates. 15
As noted above, legacy rates for agriculture will change based on the 16
MC/RA Agreement with the initial implementation of rates in this proceeding. 17
Legacy rates will then be changed based on the rules in the MC/RA 18
Settlement agreement and the rules for changing distribution and generation 19
rates as set forth below. The rates with new TOU periods, however, will not 20
be implemented for some time after the initial implementation of the 21
MC/RA Settlement Agreement. The illustrative rates set forth in this 22
Appendix A are consistent with the revenue allocation set forth in Tables 1 23
and 2 of the MC/RA Settlement Agreement, which was based on 24
March 1, 2017 effective rates. The actual rates derived at the time of 25
implementation of these rates on a voluntary basis, once adopted by the 26
CPUC, shall be designed on an overall revenue-neutral basis to collect the 27
then-required revenue allocated to each customer class. As a result, the 28
actual rates that will result when these rates are implemented on a voluntary 29
basis will vary from those shown in this Appendix A. However, these actual 30
agricultural rates shall be based on the same rate relationships provided in 31
the illustrative rates, but modified to reflect sales and revenue requirement 32
changes that take place between March 1, 2017 and the date these rates 33
become effective on a voluntary basis. In order to transition rates from the 34
(PG&E-53)
-15-
illustrative rates shown in Appendix A, to the date the rates become 1
effective, PG&E will apply the rules for rate changes between GRCs as set 2
forth in the MC/RA Settlement Agreement and as specified below. 3
1) Distribution: Rates will be designed to collect the distribution revenue 4
requirement allocated to each rate schedule as provided in the MC/RA 5
Settlement Agreement. Demand and energy charges,20 will be 6
designed to change by the same percentage change in rate necessary 7
to collect the required revenue. Demand charges will be changed by the 8
same percentage, and energy charges in total will also be changed by 9
the same percentage amount. However, the change in energy charges 10
will be determined by whatever equal cents per kWh adder is required to 11
collect the necessary change in energy charge revenue. This approach 12
to setting the distribution energy charges will ensure that the differential 13
in rates between seasons and TOU periods remains the same on a cent 14
per kWh basis for these schedules. 15
2) Generation: Rates will be designed to collect the generation revenue 16
requirement allocated to each rate schedule as provided in the 17
MC/RA Settlement Agreement. Demand and energy charges will be 18
designed to each change by the same percentage change in rate 19
necessary to collect the required revenue. Demand charges will be 20
changed by the same percentage, and energy charges in total will also 21
be changed by the same percentage amount. However, the change in 22
energy rates will be determined by whatever equal cents per kWh adder 23
is required to collect the necessary change in energy charge revenue. 24
This approach to setting the generation energy charges will ensure that 25
the differential in rates between seasons and TOU periods remains the 26
same on a cent per kWh basis. 27
20 PG&E agrees with AECA and CFBF recommendations: CFBF Recommendation 7
“PG&E’s proposed increases in agricultural customer charges should be rejected, and the current customer charges should be maintained throughout the GRC cycle.” AECA Recommendation 2. “Customer charges should be held constant at current levels, as many other rate elements are changing, and PG&E’s marginal costs used for EPMC scaling are questionable.”
(PG&E-53)
-16-
F. Grandfathered TOU Periods for Solar Customers 1
Q 20 In PG&E’s Supplemental Settlement Agreement on TOU Rates for 2
Grandfathered Solar Customers, it states that the settling parties anticipate 3
amending that agreement with rates for grandfathered agricultural solar 4
customers. Does PG&E agree that rates for solar agricultural customers 5
need to be developed? 6
A 20 Yes. D.17-01-006 requires that rates for certain solar customers that are 7
eligible to take service under the current TOU periods be developed. In the 8
Settlement Agreement on TOU Rates for Grandfathered Solar Customers, 9
the parties agreed to these rates for commercial and industrial customers. 10
PG&E believes that rates should similarly be developed for agricultural 11
customers. Like the Settlement for commercial and industrial rates, this may 12
include the basic rates, as well as rate transition plans like those developed 13
for Schedule A-6, but modified to accommodate the current agricultural rate 14
structures. PG&E and the Ag Parties have agreed to a draft transition plan 15
for grandfathered solar customers, along with rate design rules and example 16
rates. A draft amendment to the agreement has been written and it is 17
currently being reviewed by the settling parties. PG&E anticipates that the 18
amendment will be approved before the start of hearings on Agricultural 19
rate design. 20
G. Conclusion 21
PG&E has proposed basic default AG-A, AG-B, and AG-C rates with peak 22
hours all year of 5 p.m. – 8 p.m. that recognize the needs of agricultural 23
customers. In addition, PG&E has proposed an optional AG-R rate that allows 24
for two consecutive days of 100 percent off-peak pumping, again recognizing the 25
special irrigation needs of some portion of agricultural customers. PG&E’s 26
proposed simplified rates may in some cases result in bill increases 27
unacceptable to agricultural parties. PG&E proposes to work on bill mitigation 28
measures with the agricultural parties for the most impacted customers as part 29
of PG&E’s 2019 RDW proceeding. PG&E has also proposed outreach and 30
online rate tool measures that should allow agricultural parties an opportunity to 31
explore how best to minimize their bill and adapt to the new proposed rates. 32
PG&E has agreed with and sought to accommodate the concerns of AECA 33
and CFBF to the greatest extent reasonable, and looks forward to continuing to 34
(PG&E-53)
-17-
work with the agricultural parties on implementation of the new rates, as well as 1
bill mitigation measures amenable to the agricultural community. 2
(PG&E-53)
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX A
ILLUSTRATIVE PROPOSED RATES
RATE SCHEDULES AG-A, AG-B, AG-C AND AG-R
(PG&E-53)
AppA-1
PACIFIC GAS AND ELECTRIC COMPANY 1
APPENDIX A 2
ILLUSTRATIVE PROPOSED RATES 3
RATE SCHEDULES AG-A, AG-B, AG-C AND AG-R 4
The illustrative rates set forth in this Appendix A are consistent with the revenue 5
allocation set forth in Tables 1 and 2 of the Marginal Cost and Revenue Allocation 6
(MC/RA) Settlement Agreement, which was based on March 1, 2017 effective rates. 7
The actual rates derived at the time of implementation of these rates on a voluntary 8
basis, once adopted by the California Public Utilities Commission, shall be designed 9
on an overall revenue-neutral basis to collect the then-required revenue allocated to 10
each customer class. As a result, the actual rates that will result when these rates 11
are implemented on a voluntary basis will vary from those shown in this Appendix A. 12
However, these actual agricultural rates shall be based on the same rate 13
relationships provided in the illustrative rates, but modified to reflect sales and 14
revenue requirement changes that take place between March 1, 2017 and the date 15
these rates become effective on a voluntary basis. In order to transition rates from 16
the illustrative rates shown in Appendix A, to the date the rates become effective, 17
Pacific Gas and Electric Company will apply the rules for rate changes between 18
General Rate Cases as set forth in the MC/RA Settlement Agreement and as 19
specified in Rebuttal Section E of this Rebuttal Testimony, for agricultural 20
rate design. 21
Pac
ific
Gas
and
Ele
ctric
Com
pany
2017
Gen
eral
Rat
e C
ase
- Pha
se II
E
xhib
it (P
G&
E-1
), A
ppen
dix
B (J
une
30, 2
016)
Pre
sent
and
Pro
pose
d R
ates
AG-A
Dis
trG
enP
PP
Oth
erTo
tal
Dis
trG
enP
PP
Oth
erTo
tal
CO
NN
ECTE
D L
OAD
CH
ARG
E (/h
p)
Sum
mer
4.98
.00
.00
4.98
W
inte
r4.
98.0
0.0
04.
98C
urre
nt A
G-1
A/VA
/4A/
5A c
usto
mer
s w
ill tr
ansi
tion
to A
G-A
.EN
ERG
Y C
HAR
GE
(/kW
h) S
umm
er
Pea
k.0
7841
.213
05.0
1741
.029
43.3
3830
P
art-P
eak
O
ff-P
eak
.078
41.0
9337
.017
41.0
2943
.218
62 W
inte
r
Par
t-Pea
k.0
5436
.090
05.0
1741
.029
43.1
9125
O
ff-P
eak
.054
36.0
6360
.017
41.0
2943
.164
80S
uper
Off-
Pea
k.0
5436
.0
6360
.0
1741
.0
2943
.164
80
CU
STO
MER
CH
ARG
E (/m
eter
/day
).6
8895
.688
9520
.97
AG-B
Dis
trG
enP
PP
Oth
erTo
tal
Dis
trG
enP
PP
Oth
erTo
tal
DEM
AND
CH
ARG
E (/k
W)
Sec
onda
ry
Sum
mer
Max
imum
Pea
k P
erio
d.0
0.0
0.0
0.0
0
Sum
mer
Max
imum
Par
t-Pea
k P
erio
dC
urre
nt A
G-1
B/V
B/4
B/4
C c
usto
mer
s w
ill tr
ansi
tion
to A
G-B
..0
0.0
0.0
0.0
0
Sum
mer
Max
imum
7.23
.00
.00
7.23
W
inte
r Max
imum
Par
t-Pea
k P
erio
d.0
0.0
0.0
0.0
0
Win
ter M
axim
um7.
23.0
0.0
07.
23P
rimar
y
Sum
mer
Max
imum
Pea
k P
erio
d.0
0.0
0.0
0.0
0
Sum
mer
Max
imum
Par
t-Pea
k P
erio
d.0
0.0
0.0
0.0
0
Sum
mer
Max
imum
6.54
.00
.00
6.54
W
inte
r Max
imum
Par
t-Pea
k P
erio
d.0
0.0
0.0
0.0
0
Win
ter M
axim
um6.
54.0
0.0
06.
54Tr
ansm
issi
on
Sum
mer
Max
imum
Pea
k P
erio
d.0
0.0
0.0
0.0
0
Sum
mer
Max
imum
Par
t-Pea
k P
erio
d.0
0.0
0.0
0.0
0
Sum
mer
Max
imum
3.96
.00
.00
3.96
W
inte
r Max
imum
Par
t-Pea
k P
erio
d.0
0.0
0.0
0.0
0
Win
ter M
axim
um3.
96.0
0.0
03.
96
ENER
GY
CH
ARG
E (/k
Wh)
Sum
mer
P
eak
.055
93.2
1882
.016
06.0
2943
.320
23
Par
t-Pea
k
Off-
Pea
k.0
5593
.097
78.0
1606
.029
43.1
9920
Win
ter
P
art-P
eak
.039
08.0
9294
.016
06.0
2943
.177
51
Off-
Pea
k.0
3908
.066
74.0
1606
.029
43.1
5131
Sup
er O
ff-P
eak
.039
08
.066
74
.016
06
.029
43.1
5131
CU
STO
MER
CH
ARG
E (/m
eter
/day
).9
1565
.000
00.9
1565
27.8
7
PRES
ENT
RAT
ESPR
OPO
SED
RAT
ES
(PG&E-53)
AppA-2
Pac
ific
Gas
and
Ele
ctric
Com
pany
2017
Gen
eral
Rat
e C
ase
- Pha
se II
E
xhib
it (P
G&
E-1
), A
ppen
dix
B (J
une
30, 2
016)
Pre
sent
and
Pro
pose
d R
ates
PRES
ENT
RAT
ESPR
OPO
SED
RAT
ESAG
-CD
istr
Gen
PP
PO
ther
Tota
lD
istr
Gen
PP
PO
ther
Tota
l
DEM
AND
CH
ARG
E (/k
W)
Sec
onda
ry
Sum
mer
Max
imum
Pea
k P
erio
d.0
07.
94.0
07.
94
Sum
mer
Max
imum
Par
t-Pea
k P
erio
dC
urre
nt A
G-5
B/5
C c
usto
mer
s w
ill tr
ansi
tion
to A
G-C
..0
0.0
0.0
0.0
0
Sum
mer
Max
imum
7.25
.00
.00
7.25
W
inte
r Max
imum
Par
t-Pea
k P
erio
d.0
0.0
0.0
0.0
0
Win
ter M
axim
um7.
25.0
0.0
07.
25P
rimar
y
Sum
mer
Max
imum
Pea
k P
erio
d.0
07.
94.0
07.
94
Sum
mer
Max
imum
Par
t-Pea
k P
erio
d.0
0.0
0.0
0.0
0
Sum
mer
Max
imum
6.31
.00
.00
6.31
W
inte
r Max
imum
Par
t-Pea
k P
erio
d.0
0.0
0.0
0.0
0
Win
ter M
axim
um6.
31.0
0.0
06.
31Tr
ansm
issi
on
Sum
mer
Max
imum
Pea
k P
erio
d.0
07.
94.0
07.
94
Sum
mer
Max
imum
Par
t-Pea
k P
erio
d.0
0.0
0.0
0.0
0
Sum
mer
Max
imum
2.35
.00
.00
2.35
W
inte
r Max
imum
Par
t-Pea
k P
erio
d.0
0.0
0.0
0.0
0
Win
ter M
axim
um2.
35.0
0.0
02.
35
ENER
GY
CH
ARG
E (/k
Wh)
Sum
mer
P
eak
.020
06.1
1028
.012
72.0
2943
.172
49
Par
t-Pea
k
Off-
Pea
k.0
2006
.077
53.0
1272
.029
43.1
3974
Win
ter
P
art-P
eak
.017
02.0
8583
.012
72.0
2943
.144
99
Off-
Pea
k.0
1702
.060
31.0
1272
.029
43.1
1947
Sup
er O
ff-P
eak
.017
02
.060
31
.012
72
.029
43.1
1947
CU
STO
MER
CH
ARG
E (/m
eter
/day
)1.
4334
3.0
0000
1.43
343
43.6
3
AG-1
Dis
trG
enP
PP
Oth
erTo
tal
CO
NN
ECTE
D L
OAD
CH
ARG
E (/h
p)R
ate
A
Sum
mer
6.60
1.36
.000
007.
96Se
e sc
hedu
les
AG-A
or A
G-B
abo
ve
Win
ter
1.52
.00
.000
001.
52
DEM
AND
CH
ARG
E (/k
W)
Rat
e B
Sec
onda
ry M
axim
um D
eman
d
Sum
mer
9.59
2.04
.000
0011
.63
W
inte
r2.
34.0
0.0
0000
2.34
Prim
ary
Max
imum
Dem
and
S
umm
er9.
131.
29.0
0000
10.4
2
Win
ter
2.02
.00
.000
002.
02
ENER
GY
CH
ARG
E (/k
Wh)
Rat
e A
Sum
mer
.133
38.0
9932
.017
27.0
2943
.279
40
W
inte
r.0
8892
.079
66.0
1727
.029
43.2
1528
Rat
e B
S
umm
er.0
9139
.102
28.0
1595
.029
43.2
3905
W
inte
r.0
6093
.079
73.0
1595
.029
43.1
8604
CU
STO
MER
CH
ARG
E (/m
eter
/day
)R
ate
A.5
7400
.574
0017
.47
Rat
e B
.763
13.7
6313
23.2
3
(PG&E-53)
AppA-3
Pac
ific
Gas
and
Ele
ctric
Com
pany
2017
Gen
eral
Rat
e C
ase
- Pha
se II
E
xhib
it (P
G&
E-1
), A
ppen
dix
B (J
une
30, 2
016)
Pre
sent
and
Pro
pose
d R
ates
PRES
ENT
RAT
ESPR
OPO
SED
RAT
ES
AG-R
Dis
trG
enP
PP
Oth
erTo
tal
Dis
trG
enP
PP
Oth
erTo
tal
CO
NN
ECTE
D L
OAD
CH
ARG
E (/h
p)R
ate
A
Sum
mer
5.77
1.31
.00
7.08
4.98
.00
.00
4.98
W
inte
r1.
16.0
0.0
01.
164.
98.0
0.0
04.
98
DEM
AND
CH
ARG
E (/k
W)
Rat
e B
Sec
onda
ry
Sum
mer
Max
imum
Pea
k P
erio
d1.
512.
18.0
03.
69-
-
-
-
Sum
mer
Max
imum
7.65
1.94
.00
9.59
7.23
.00
.00
7.23
W
inte
r Max
imum
1.93
.00
.00
1.93
7.23
.00
.00
7.23
Prim
ary
S
umm
er M
axim
um P
eak
Per
iod
1.51
2.18
.00
3.69
-
-
.00
-
S
umm
er M
axim
um7.
321.
45.0
08.
776.
54.0
0.0
06.
54
Win
ter M
axim
um1.
62.0
0.0
01.
626.
54.0
0.0
06.
54Tr
ansm
issi
on
Sum
mer
Max
imum
Pea
k P
erio
d-
-
-
-
-
-
.0
0-
Sum
mer
Max
imum
-
-
-
-
3.96
.00
.00
3.96
W
inte
r Max
imum
-
-
-
-
3.96
.00
.00
3.96
Rat
e C
Sec
onda
ry
Sum
mer
Max
imum
Pea
k P
erio
d-
-
-
-
.0
07.
94.0
07.
94
Sum
mer
Max
imum
-
-
-
-
7.25
.00
.00
7.25
W
inte
r Max
imum
-
-
-
-
7.25
.00
.00
7.25
Prim
ary
S
umm
er M
axim
um P
eak
Per
iod
-
-
-
-
.00
7.94
.00
7.94
S
umm
er M
axim
um-
-
-
-
6.
31.0
0.0
06.
31
Win
ter M
axim
um-
-
-
-
6.
31.0
0.0
06.
31Tr
ansm
issi
on
Sum
mer
Max
imum
Pea
k P
erio
d-
-
-
-
.0
07.
94.0
07.
94
Sum
mer
Max
imum
-
-
-
-
2.35
.00
.00
2.35
W
inte
r Max
imum
-
-
-
-
2.35
.00
.00
2.35
ENER
GY
CH
ARG
E (/k
Wh)
Rat
e A
Sum
mer
P
eak
.213
20.2
6735
.017
27.0
2943
.527
24.1
4430
.178
39.0
1741
.029
43.3
6953
O
ff-P
eak
.071
06.0
6733
.017
27.0
2943
.185
09.0
7215
.101
25.0
1741
.029
43.2
2024
Win
ter
P
art-P
eak
.067
53.0
7446
.017
27.0
2943
.188
68.0
9934
.091
05.0
1741
.029
43.2
3724
O
ff-P
eak
.045
01.0
6338
.017
27.0
2943
.155
09.0
4967
.064
60.0
1741
.029
43.1
6111
Rat
e B
Sum
mer
P
eak
.188
21.2
4143
.015
95.0
2943
.475
02.1
0286
.185
79.0
1606
.029
43.3
3414
O
ff-P
eak
.062
71.0
6684
.015
95.0
2943
.174
92.0
5143
.105
57.0
1606
.029
43.2
0249
Win
ter
P
art-P
eak
.057
54.0
6131
.015
95.0
2943
.164
23.0
7128
.094
17.0
1606
.029
43.2
1094
O
ff-P
eak
.038
31.0
5222
.015
95.0
2943
.135
90.0
3564
.067
72.0
1606
.029
43.1
4885
Rat
e C
Sum
mer
P
eak
-
-
-
-
-
.036
78.1
0897
.012
72.0
2943
.187
89
Off-
Pea
k-
-
-
-
-
.0
1839
.078
95.0
1272
.029
43.1
3949
Win
ter
P
art-P
eak
-
-
-
-
-
.031
19.0
8759
.012
72.0
2943
.160
93
Off-
Pea
k-
-
-
-
-
.0
1560
.061
14.0
1272
.029
43.1
1888
CU
STO
MER
CH
ARG
E (/m
eter
/day
)R
ate
A.5
7400
.574
0017
.47
.688
95.6
8895
20.9
7R
ate
B.7
6313
.763
1323
.23
.915
65.9
1565
27.8
7R
ate
C-
-
-
1.43
343
1.43
343
43.6
3
(PG&E-53)
AppA-4
Pac
ific
Gas
and
Ele
ctric
Com
pany
2017
Gen
eral
Rat
e C
ase
- Pha
se II
E
xhib
it (P
G&
E-1
), A
ppen
dix
B (J
une
30, 2
016)
Pre
sent
and
Pro
pose
d R
ates
PRES
ENT
RAT
ESPR
OPO
SED
RAT
ESAG
-VD
istr
Gen
PP
PO
ther
Tota
lC
ON
NEC
TED
LO
AD C
HAR
GE
(/hp)
Rat
e A
S
umm
er5.
731.
37.0
07.
10Se
e sc
hedu
les
AG-A
or A
G-B
abo
ve
Win
ter
1.20
.00
.00
1.20
DEM
AND
CH
ARG
E (/k
W)
Rat
e B
Sec
onda
ry
Sum
mer
Max
imum
Pea
k P
erio
d1.
372.
29.0
03.
66
Sum
mer
Max
imum
7.87
1.78
.00
9.66
W
inte
r Max
imum
1.91
.00
.00
1.91
Prim
ary
S
umm
er M
axim
um P
eak
Per
iod
1.37
2.29
.000
003.
66
Sum
mer
Max
imum
7.51
1.26
.000
008.
77
Win
ter M
axim
um1.
61.0
0.0
0000
1.61
ENER
GY
CH
ARG
E (/k
Wh)
Rat
e A
Sum
mer
P
eak
.212
00.2
3392
.017
27.0
2943
.492
61
Off-
Pea
k.0
7064
.064
62.0
1727
.029
43.1
8195
Win
ter
P
art-P
eak
.070
32.0
7294
.017
27.0
2943
.189
95
Off-
Pea
k.0
4685
.062
09.0
1727
.029
43.1
5563
Rat
e B
Sum
mer
P
eak
.178
94.2
1601
.015
95.0
2943
.440
33
Off-
Pea
k.0
5967
.065
02.0
1595
.029
43.1
7006
Win
ter
P
art-P
eak
.054
67.0
6154
.015
95.0
2943
.161
59
Off-
Pea
k.0
3644
.052
40.0
1595
.029
43.1
3422
CU
STO
MER
CH
ARG
E (/m
eter
/day
)R
ate
A.5
7400
.574
0017
.47
Rat
e B
.763
13.7
6313
23.2
3
(PG&E-53)
AppA-5
Pac
ific
Gas
and
Ele
ctric
Com
pany
2017
Gen
eral
Rat
e C
ase
- Pha
se II
E
xhib
it (P
G&
E-1
), A
ppen
dix
B (J
une
30, 2
016)
Pre
sent
and
Pro
pose
d R
ates
PRES
ENT
RAT
ESPR
OPO
SED
RAT
ESAG
-4D
istr
Gen
PP
PO
ther
Tota
lC
ON
NEC
TED
LO
AD C
HAR
GE
(/hp)
Rat
e A
S
umm
er6.
771.
35.0
0000
8.12
See
sche
dule
s AG
-A o
r AG
-B a
bove
W
inte
r1.
23.0
0.0
0000
1.23
DEM
AND
CH
ARG
E (/k
W)
Rat
e B
Sec
onda
ry
Sum
mer
Max
imum
Pea
k P
erio
d2.
632.
54.0
0000
5.18
S
umm
er M
axim
um7.
402.
39.0
0000
9.79
W
inte
r Max
imum
2.26
.00
.000
002.
26P
rimar
y
Sum
mer
Max
imum
Pea
k P
erio
d2.
632.
54.0
0000
5.18
S
umm
er M
axim
um6.
961.
80.0
0000
8.76
W
inte
r Max
imum
1.91
.00
.000
001.
91
Rat
e C
Sec
onda
ry
Sum
mer
Max
imum
Pea
k P
erio
d6.
255.
85.0
0000
12.0
9
Sum
mer
Max
imum
Par
t-Pea
k P
erio
d1.
311.
00.0
0000
2.31
S
umm
er M
axim
um4.
96.0
0.0
0000
4.96
W
inte
r Max
imum
Par
t-Pea
k P
erio
d.5
4.0
0.0
0000
.54
W
inte
r Max
imum
2.40
.00
.000
002.
40P
rimar
y
Sum
mer
Max
imum
Pea
k P
erio
d5.
924.
83.0
0000
10.7
6
Sum
mer
Max
imum
Par
t-Pea
k P
erio
d1.
311.
00.0
0000
2.31
S
umm
er M
axim
um4.
96.0
0.0
0000
4.96
W
inte
r Max
imum
Par
t-Pea
k P
erio
d.5
4.0
0.0
0000
.54
W
inte
r Max
imum
2.09
.00
.000
002.
09Tr
ansm
issi
on
Sum
mer
Max
imum
Pea
k P
erio
d1.
793.
98.0
0000
5.77
S
umm
er M
axim
um P
art-P
eak
Per
iod
.00
1.02
.000
001.
02
Sum
mer
Max
imum
4.72
.00
.000
004.
72
Win
ter M
axim
um P
art-P
eak
Per
iod
.00
.00
.000
00.0
0
Win
ter M
axim
um.7
3.0
0.0
0000
.73
ENER
GY
CH
ARG
E (/k
Wh)
Rat
e A
Sum
mer
P
eak
.239
20.1
5892
.017
27.0
2943
.444
82
Off-
Pea
k.0
7973
.068
61.0
1727
.029
43.1
9503
Win
ter
P
art-P
eak
.082
39.0
7271
.017
27.0
2943
.201
80
Off-
Pea
k.0
5492
.061
95.0
1727
.029
43.1
6357
Rat
e B
Sum
mer
P
eak
.124
42.1
2171
.015
95.0
2943
.291
50
Off-
Pea
k.0
4145
.070
64.0
1595
.029
43.1
5746
Win
ter
P
art-P
eak
.043
58.0
6888
.015
95.0
2943
.157
84
Off-
Pea
k.0
2908
.058
61.0
1595
.029
43.1
3306
Rat
e C
Sum
mer
P
eak
.081
34.1
3933
.015
95.0
2943
.266
05
Par
t-Pea
k.0
3251
.078
88.0
1595
.029
43.1
5677
O
ff-P
eak
.016
29.0
5691
.015
95.0
2943
.118
57 W
inte
r
Par
t-Pea
k.0
2261
.063
15.0
1595
.029
43.1
3114
O
ff-P
eak
.015
03.0
5371
.015
95.0
2943
.114
12
(PG&E-53)
AppA-6
Pac
ific
Gas
and
Ele
ctric
Com
pany
2017
Gen
eral
Rat
e C
ase
- Pha
se II
E
xhib
it (P
G&
E-1
), A
ppen
dix
B (J
une
30, 2
016)
Pre
sent
and
Pro
pose
d R
ates
PRES
ENT
RAT
ESPR
OPO
SED
RAT
ESAG
-4 (c
ontin
ued)
Dis
trG
enP
PP
Oth
erTo
tal
CU
STO
MER
CH
ARG
E (/m
eter
/day
)R
ate
A.5
7400
.574
0017
.47
See
sche
dule
s AG
-A o
r AG
-B a
bove
Rat
e B
.763
13.7
6313
23.2
3R
ate
C2.
1500
32.
1500
365
.44
AG-5
Dis
trG
enP
PP
Oth
erTo
tal
CO
NN
ECTE
D L
OAD
CH
ARG
E (/h
p)R
ate
A
Sum
mer
8.07
3.70
.000
0011
.77
W
inte
r2.
19.0
0.0
0000
2.19
DEM
AND
CH
ARG
E (/k
W)
Rat
e B
Sec
onda
ry
Sum
mer
Max
imum
Pea
k P
erio
d4.
285.
57.0
0000
9.84
See
sche
dule
AG
-C a
bove
S
umm
er M
axim
um10
.92
4.45
.000
0015
.37
W
inte
r Max
imum
5.95
.00
.000
005.
95P
rimar
y
Sum
mer
Max
imum
Pea
k P
erio
d4.
285.
57.0
0000
9.84
S
umm
er M
axim
um10
.60
3.05
.000
0013
.65
W
inte
r Max
imum
5.77
.00
.000
005.
77Tr
ansm
issi
on
Sum
mer
Max
imum
Pea
k P
erio
d4.
285.
57.0
0000
9.84
S
umm
er M
axim
um1.
852.
02.0
0000
3.87
W
inte
r Max
imum
.83
.00
.000
00.8
3
DEM
AND
CH
ARG
E (/k
W)
Rat
e C
Sec
onda
ry
Sum
mer
Max
imum
Pea
k P
erio
d6.
3410
.28
.000
0016
.62
S
umm
er M
axim
um P
art-P
eak
Per
iod
1.51
1.93
.000
003.
44
Sum
mer
Max
imum
5.95
.00
.000
005.
95
Win
ter M
axim
um P
art-P
eak
Per
iod
.89
.00
.000
00.8
9
Win
ter M
axim
um3.
71.0
0.0
0000
3.71
Prim
ary
S
umm
er M
axim
um P
eak
Per
iod
5.97
8.16
.000
0014
.13
S
umm
er M
axim
um P
art-P
eak
Per
iod
1.51
1.93
.000
003.
44
Sum
mer
Max
imum
5.95
.00
.000
005.
95
Win
ter M
axim
um P
art-P
eak
Per
iod
.89
.00
.000
00.8
9
Win
ter M
axim
um3.
46.0
0.0
0000
3.46
Tran
smis
sion
S
umm
er M
axim
um P
eak
Per
iod
.00
6.32
.000
006.
32
Sum
mer
Max
imum
Par
t-Pea
k P
erio
d.0
01.
93.0
0000
1.93
S
umm
er M
axim
um2.
56.0
0.0
0000
2.56
W
inte
r Max
imum
Par
t-Pea
k P
erio
d.0
0.0
0.0
0000
.00
W
inte
r Max
imum
1.28
.00
.000
001.
28
(PG&E-53)
AppA-7
Pac
ific
Gas
and
Ele
ctric
Com
pany
2017
Gen
eral
Rat
e C
ase
- Pha
se II
E
xhib
it (P
G&
E-1
), A
ppen
dix
B (J
une
30, 2
016)
Pre
sent
and
Pro
pose
d R
ates
PRES
ENT
RAT
ESPR
OPO
SED
RAT
ESAG
-5 (c
ontin
ued)
Dis
trG
enP
PP
Oth
erTo
tal
ENER
GY
CH
ARG
E (/k
Wh)
Rat
e A
Sum
mer
P
eak
.112
02.1
4873
.017
27.0
2943
.307
44Se
e sc
hedu
les
AG-A
or A
G-B
abo
ve
Off-
Pea
k.0
3734
.073
53.0
1727
.029
43.1
5757
Win
ter
P
art-P
eak
.042
17.0
7701
.017
27.0
2943
.165
88
Off-
Pea
k.0
2811
.065
68.0
1727
.029
43.1
4049
Rat
e B
Sum
mer
P
eak
.023
03.1
4527
.012
18.0
2943
.209
90Se
e sc
hedu
le A
G-C
abo
ve
Off-
Pea
k.0
0145
.048
84.0
1218
.029
43.0
9189
Win
ter
P
art-P
eak
.001
45.0
6894
.012
18.0
2943
.111
99
Off-
Pea
k.0
0145
.040
53.0
1218
.029
43.0
8358
Rat
e C
Sum
mer
P
eak
.000
98.1
1976
.012
18.0
2943
.162
34
Par
t-Pea
k.0
0098
.069
15.0
1218
.029
43.1
1173
O
ff-P
eak
.000
98.0
5031
.012
18.0
2943
.092
89 W
inte
r
Par
t-Pea
k.0
0098
.055
96.0
1218
.029
43.0
9853
O
ff-P
eak
.000
98.0
4739
.012
18.0
2943
.089
97
CU
STO
MER
CH
ARG
E (/m
eter
/day
)R
ate
A.5
7400
.574
0017
.47
Rat
e B
1.19
446
1.19
446
36.3
6R
ate
C5.
3087
15.
3087
116
1.58
(PG&E-53)
AppA-8
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX B
ILLUSTRATIVE BILL IMPACTS OF PRESENT VERSUS
PROPOSED TOTAL RATES
(PG&E-53)
AppB-1
PACIFIC GAS AND ELECTRIC COMPANY 1
APPENDIX B 2
ILLUSTRATIVE BILL IMPACTS OF PRESENT VERSUS PROPOSED 3
TOTAL RATES 4
The illustrative bill impacts set forth in this Appendix B are consistent with the 5
revenue allocation set forth in Tables 1 and 2 of the Marginal Cost and Revenue 6
Allocation (MC/RA) Settlement Agreement, as well as with the illustrative agricultural 7
rates set forth in Appendix A, based on March 1, 2017 effective rates. 8
The bill impacts in Appendix B are presented for customers on each legacy rate 9
schedule, under the following assignments of customers on each legacy rate 10
schedule to the new proposed basic Schedules AG-A, AG-B, and AG-C. 11
Legacy Agricultural Rate Schedule Assigned New Proposed Agricultural Rate 12
AG-4A, AG-5A, AG-RA, AG-VA AG-A 13
AG-4B, AG-4C, AG-RB, AG-VB AG-B 14
AG-5B, AG-5C AG-C with a $0.50 per kWh Demand Charge 15
Limiter (DCL) 16 NOTES: 17 [1] Legacy AG-1A customers were treated as if currently on AG-4A. 18 [2] Legacy AG-1B customers were treated as if currently on AG-4B. 19 [3] Legacy AG-ICE customers were treated as if currently on AG-5B. 20 [4] New Schedule AG-R bill impacts are not shown in Appendix B, for bill impacts on the 21
new proposed opt-in Schedules AG-RA, AG-RB, or AG-RC. 22 [5] Compared to PG&E’s prior filed Appendix G illustrative bill impacts, PG&E has added 23
an average monthly bill amount column at right, and row at the bottom, showing the 24 average monthly bill for all customers in that column or row. 25
[6] The revenue shortfall from the new proposed Schedule AG-C $0.50 per kWh DCL is 26 estimated but has not been incorporated into the rates in Appendix A used to run the bill 27 impacts. PG&E estimates that the AG-C DCL would result in approximately $4.6 million 28 in bill savings per year, and an equal cent adder to the Schedule AG-C Distribution 29 energy rates shown in Appendix A of $0.00084 per kWh. 30
(PG&E-53)
A P
erce
ntag
e di
ffere
nce
whi
ch fa
lls o
n a
colu
mn
boun
dary
is in
clud
ed in
the
high
er c
olum
n
RA
TE D
ATA
AN
ALY
SIS
BIL
L IM
PAC
T SU
MM
AR
Y1
CU
RR
ENT:
Cur
rent
Mar
ch 2
017
rate
sPR
OPO
SED
: New
5-8
pm A
G-A
BC
: N
ew A
G-A
Sm
all,
AG
-B M
ediu
m, A
G-C
Lar
ge R
ates
(with
DC
L)
FOR
AN
NU
AL
for N
on-N
EM C
usto
mer
sU
sing
Jan
201
6-D
ec 2
016
Inte
rval
Dat
a
A P
erce
ntag
e di
ffere
nce
whi
ch fa
lls o
n a
colu
mn
boun
dary
is in
clud
ed in
the
high
er c
olum
n
RA
TE D
ATA
AN
ALY
SIS
BIL
L IM
PAC
T SU
MM
AR
Y1
CU
RR
ENT:
Cur
rent
Mar
ch 2
017
rate
sPR
OPO
SED
: New
5-8
pm A
G-A
BC
: N
ew A
G-A
Sm
all,
AG
-B M
ediu
m, A
G-C
Lar
ge R
ates
(with
DC
L)
FOR
AN
NU
AL
for N
on-N
EM C
usto
mer
sU
sing
Jan
201
6-D
ec 2
016
Inte
rval
Dat
a
Rat
e Sc
hedu
le=A
G4A
$M
ON
THLY
$PC
TD
IFFE
REN
CEB
ELO
W-2
0%D
ECR
EASE
-20
- -10
%D
ECR
EASE
-10
- -5%
DEC
REA
SE-5
- -2
.5%
DEC
REA
SE-2
.5 -
0%D
ECR
EASE
0 - 2
.5%
INC
REA
SE2.
5 - 5
%IN
CR
EASE
5 - 1
0%IN
CR
EASE
10 -
20%
INC
REA
SEA
BO
VE20
%IN
CR
EASE
AVG
.MO
BIL
L4%
-11
9.00
779(
2.5%
)39
4(1.
3%)
60(0
.2%
)5(
0.0%
)0
00
00
0$5
42.9
18%
$-9
4.13
832(
2.7%
)33
1(1.
1%)
72(0
.2%
)4(
0.0%
)0
00
00
0$3
58.7
412
% $
-79.
2580
2(2.
6%)
349(
1.1%
)86
(0.3
%)
2(0.
0%)
00
00
00
$292
.32
16%
$-6
7.13
762(
2.5%
)39
9(1.
3%)
83(0
.3%
)2(
0.0%
)0
00
00
0$2
71.8
120
% $
-59.
4686
2(2.
8%)
287(
0.9%
)76
(0.2
%)
5(0.
0%)
00
00
00
$194
.10
24%
$-5
1.16
664(
2.1%
)43
3(1.
4%)
130(
0.4%
)13
(0.0
%)
00
00
00
$254
.73
28%
$-4
3.65
645(
2.1%
)41
6(1.
3%)
171(
0.6%
)21
(0.1
%)
1(0.
0%)
00
00
0$2
39.6
332
% $
-39.
6283
6(2.
7%)
264(
0.9%
)10
9(0.
4%)
12(0
.0%
)2(
0.0%
)0
00
00
$147
.49
36%
$-3
4.21
634(
2.0%
)39
2(1.
3%)
184(
0.6%
)22
(0.1
%)
4(0.
0%)
00
00
0$1
96.3
940
% $
-30.
7781
1(2.
6%)
261(
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201
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Inte
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Inte
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201
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Inte
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201
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AppB-11
(PG&E-53)
