docs.cpuc.ca.govSTATEMENT OF QUALIFICATIONS OF LAURA B. NORIN Q. Please state your name and business...

STATEMENT OF QUALIFICATIONS OF LAURA B. NORIN

Q. Please state your name and business address.

A. My name is Laura Norin. I am a Senior Project Manager with MRW & Associates,

LLC (“MRW”). MRW is an energy consulting firm that was founded in 1986. MRW

specializes in power and gas market assessments, regulatory matters, litigation support,

expert witness testimony, contract review, and negotiations. My business address is 1814

Franklin Street, Suite 720, Oakland, California.

Q. Briefly summarize your educational background and professional experience.

A. Since 2004 I have been working at MRW where I have been focusing on California’s

electricity and natural gas markets, regulations, and policies. During this time, I have

worked with energy policy makers, financial institutions, energy suppliers, and municipal

and industrial end-users on a variety of issues, including electricity ratemaking, departing

load exit fees, asset valuation, and wholesale and retail electricity price forecasting.

Previously, I worked as a research associate at Lawrence Berkeley National Lab’s

Environmental Energy Technology Division. I have a Masters Degree in Applied Physics

from the University of California, Berkeley.

Q. Have you ever testified before this Commission?

A. Yes. A list of prepared testimony follows my resume.

Q. For whom are you submitting this testimony?

A. I am submitting this testimony of behalf of the California Farm Bureau Federation.

RESUME OF LAURA B. NORIN

PROFESSIONAL Senior Project Manager EXPERIENCE MRW & Associates, LLC (2004-Present)

Conduct quantitative and qualitative analyses related to energy regulation, policy, commerce, and litigation. Research and develop policy reports and participate in regulatory proceedings. Prepare expert witness testimony in utility rate cases and other proceedings before the California Public Utilities Commission. Construct models to forecast retail electricity rates and assess generation alternatives. Major projects include work on nuclear energy policy, retail energy markets, natural gas storage, and resource adequacy.

Graduate Student Researcher UC-Berkeley (2002-2004)

Conducted biophysics research related to cellular interaction mechanisms.

Research Associate Lawrence Berkeley National Lab (2001-2002)

Used microscopic and spectroscopic techniques to investigate the sources of battery failure in high-power batteries being developed for hybrid vehicles.

Research Assistant Fieldston Company (1996)

Conducted research and quantitative analysis related to domestic energy transportation. A major project involved analyzing the finances of domestic freight railroads as part of a study on the effects of railroad consolidation on deregulating utilities.

EDUCATION M.S., Applied Physics, University of California, Berkeley, 2004 B.S., Physics, University of California, Berkeley, 2001

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Prepared Testimony of Laura B. Norin

1. CPUC Application 09-12-020 Direct Testimony of South San Joaquin Irrigation District Concerning PG&E’s 2011 General Rate Case Phase 1 Application (with Steven C. McClary). May 19, 2010.

2. CPUC Application 10-03-014

Direct Testimony of Laura Norin on Behalf of South San Joaquin Irrigation District Concerning PG&E’s 2011 General Rate Case Phase II Application. October 6, 2010.


Testimony of Steven McClary and Laura Norin on Behalf of UCAN Concerning SDG&E’s General Rate Case. September 22, 2011.

4. CPUC Application 11-05-023 Testimony of Laura Norin on Behalf of UCAN Concerning SDG&E’s Application for Authority to Enter into Purchase Power Tolling Agreements with Escondido Energy Center, Pio Pico Energy Center and Quail Brush Power. September 23, 2011.

5. CPUC Rulemaking 11-03-012

Proposal of Laura B. Norin on Behalf of the California Farm Bureau Federation, the Agricultural Council of California, the California League of Food Processors, and the Agricultural Energy Consumers Association (the “Agricultural Parties”) Concerning the Allocation and Use of Greenhouse Gas Allowance Auction Revenues. January 6, 2012.

6. CPUC Application 11-06-007 Testimony of Laura Norin on Behalf of the Coalition for Affordable Street Lights Concerning SCE's Proposed Street Light Rates. February 6, 2012.


Testimony of Steven McClary and Laura Norin on Behalf of San Diego Consumers’ Action Network (SDCAN) Concerning SDG&E’s General Rate Case Phase II. June 12, 2012.

8. CPUC Application 13-08-002 et al Testimony of Laura Norin on Behalf of the California Farm Bureau Federation Concerning the Investor-owned Utilities’ Greenhouse Gas Implementation Plans. October 9, 2013.

9. CPUC Application 13-08-004 Testimony of Laura Norin on Behalf of the Public Agency Coalition Concerning SCE’s Undercollection Tracking. November 20, 2013.

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10. CPUC Application 13-04-012 Testimony of Laura Norin on Behalf of the California Farm Bureau Federation Concerning PG&E’s Marginal Cost Studies and Agricultural Rate Deign Proposals. December 13, 2013.

11. CPUC Application 13-11-003 Testimony of Laura Norin on Behalf of the Coalition for Affordable Street Lights (CASL) Concerning SCE’s Street Light-Related Revenue Request. August 18, 2014.

12. CPUC Application 14-05-024 Direct Testimony of Agricultural Energy Consumers Association and the California Farm Bureau Federation. August 22, 2014.

13. CPUC Application 14-01-027 Testimony of Laura Norin on Behalf of the California Farm Bureau Federation Concerning SDG&E’s Rate Design Window Proposals. November 14, 2014.

14. CPUC Application 14-01-027 Rebuttal Testimony of Laura Norin on Behalf of the California Farm Bureau Federation Concerning SDG&E’s Rate Design Window Proposals. December 12, 2014.

15. CPUC Application 14-06-014 Testimony of Laura Norin on Behalf of the California Farm Bureau Federation Concerning SCE’s 2015 General Rate Case Phase 2 Application. March 13, 2015.

16. CPUC Application 14-11-003 Testimony of Briana Kobor, Laura Norin, and Mark Fulmer on Behalf of the Utility Consumers' Action Network Concerning Sempra's Revenue Requirement Proposals for SDG&E and SoCal Gas. May 15, 2015.

17. CPUC Application 14-12-007 Testimony of Mark Fulmer and Laura Norin on Behalf of the Utility Consumers' Action Network Concerning Risk Assignment of SONGS Decommissioning Costs. July 15, 2015.

18. CPUC Application 14-12-007 Rebuttal Testimony of Mark Fulmer and Laura Norin on Behalf of the Utility Consumers' Action Network Concerning Risk Assignment of SONGS Decommissioning Costs. August 3, 2015.

19. CPUC Application 15-09-001 Prepared Testimony of Laura Norin and Brandon Charles on Behalf of South San Joaquin Irrigation District. April 29, 2016.

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20. CPUC Application 15-09-001 Rebuttal Testimony of Laura Norin on Behalf of South San Joaquin Irrigation District. May 27, 2016.

21. CPUC Application 15-04-012 Testimony of Laura Norin and Brandon Charles on Behalf of the California Farm Bureau Federation Concerning San Diego Gas& Electric’s 2016 General Rate Case Phase 2 Application. July 5, 2016.

STATEMENT OF QUALIFICATIONS OF BRANDON J. CHARLES

Q. Please state your name and business address.

A. My name is Brandon Charles. I am a Senior Associate with MRW & Associates, LLC

(“MRW”). MRW is an energy consulting firm that was founded in 1986. MRW specializes in

power and gas market assessments, regulatory matters, litigation support, expert witness

testimony, contract review, and negotiations. My business address is 1814 Franklin Street, Suite

720, Oakland, California.

Q. Briefly summarize your educational background and professional experience.

A. I have worked at MRW for approximately six years, with a focus on California’s electricity and

natural gas markets, regulations, and policies. During this time, I have worked with energy

policy makers, financial institutions, energy suppliers, and municipal and industrial end-users on

a variety of issues, including electricity ratemaking, departing load exit fees, and wholesale and

retail electricity price forecasting. I have also worked at Bloom Energy, where I analyzed

electricity and natural gas market prices and trends, market strategy and size, and distributed

energy project economics. I hold a bachelor’s degree in economics from Dartmouth College.

Q. Have you ever testified before this Commission?

A. Yes, I have previously testified on behalf of the South San Joaquin Irrigation District and the

California Farm Bureau Federation.

Q. For whom are you submitting this testimony?

A. I am submitting this testimony of behalf of the California Farm Bureau Federation.

BRANDON J. CHARLES

PROFESSIONAL Senior Associate EXPERIENCE MRW & Associates, LLC (September 2008 – May 2013, March 2016 - present) Analyze electricity and natural gas market data with a focus on markets in the

western U.S. Develop models forecasting retail and wholesale electricity prices. Analyze and develop expert testimony regarding utility ratemaking and policy proposals. Research and interpret policy decisions and proposals affecting the energy market and develop reports on energy policy and market issues.

Senior Market Analyst Bloom Energy (June 2013 – March 2016) Analyzed electricity and natural gas market prices and trends, regulatory policies

impacting distributed generation markets, new market opportunities, stationary fuel cell addressable market size, and the economics of potential product offerings. Developed cash flow models and assumptions for distributed generation project economics for Fortune 500 customers and state policymakers.

Coordinator, Economic and International Policy

Biotechnology Industry Organization (BIO) (September 2006 – August 2008) Analyzed industry trends, legislative and regulatory policy developments, and economic issues in support of industry policy positions and related studies. Legal Assistant White & Case, LLP (July 2005 – June 2006) Managed U.S. litigation and international arbitration cases, including the arbitration of an international power plant development contract.

EDUCATION A.B., Economics, Dartmouth College, 2005

GRC-2017-PhII_DR_CFBF_002-Q09 Page 1

PACIFIC GAS AND ELECTRIC COMPANY 2017 General Rate Case Phase II

Application 16-06-013 Data Response

PG&E Data Request No.: CFBF_002-Q09 PG&E File Name: GRC-2017-PhII_DR_CFBF_002-Q09 Request Date: October 11, 2016 Requester DR No.: 002 Date Sent: November 14, 2016 Requesting Party: California Farm Bureau

Federation PG&E Witness: Keith Coyne Requester: Karen Mills

QUESTION 9

PG&E-1, p. 1-14 states, “PG&E proposes to revise the level of the customer charge with the level of distribution demand energy charges when distribution revenue changes between GRCs.”

a. Please provide a workpaper calculating how the customer charges and distribution demand energy charges for AG-A, AG-B, and AG-C customers would be adjusted between 2017 and 2020 in response to the distribution revenue changes that would be implemented in each year per the proposed settlement in PG&E’s GRC I.

b. Please describe PG&E’s proposed mechanisms for making these between-GRC rate adjustments.

c. Per PG&E’s proposal, would customer charge adjustments be made as part of the beginning of the year rate change, or could there be multiple customer charge adjustments per year?

d. Per PG&E’s proposal, would all distribution revenue changes result in revisions to the customer charge level, or just base revenue changes or some other subset of distribution revenue changes (please specify)?

ANSWER 9a

PG&E has not prepared or filed a rate design model to implement distribution revenue requirement changes between GRCs. However, PG&E has provided a conceptual example, in Attachment “GRC2017-Ph-II_DR_CFBF_002-Q09a-Atch01.xls” to this data request, showing how generation and distribution changes would be implemented. .

ANSWER 9b

The Revenue Allocation and Rate Design Policy Chapter 1, at page 1-13 lines 5 to 8, and at the top of page 1-14, and in Attachment B generally, part g specifically, and Agricultural Chapter 7, pages 7-16 to 7-17, describe PG&E’s proposed interim rate changes.

ANSWER 9c


Yes, customer charges can change both upon implementation and with each future rate change. Please see the description in Policy Chapter 1, at page 1-13, lines 7 to 8, and at the top of page 1-14. Generally, PG&E intends that all customer charges be revised immediately upon implementation of a final decision in this GRC Phase II proceeding to move them to the proposed new customer charge levels if adopted. However, PG&E does not intend to do so for the agricultural sector because for the agricultural sector, PG&E proposes consolidating thirteen current Legacy rate schedules to three proposed new, streamlined agricultural rate schedules.

The initial GRC Phase II implementation will apply only to Legacy agricultural rates, as the new agricultural streamlined rates will not be implemented until several months later. However, for the initial implementation of Phase II rates, the customer charges in the Legacy agricultural schedules (and all customer charges in non-agricultural customer classes) would include a change if there is any underlying concomitant distribution component concurrent revenue requirement change (such as if GRC Phase II immediate initial implementation were concurrent with the Annual Electric True-Up (AET) rate change). All customer charges in all classes would also change with each subsequent future distribution revenue requirement rate change. In addition, when the new AG-A, AG-B, and AG-C rates become available on an opt-in basis, if there are any concurrent changes to the underlying distribution component revenue requirement, customer charges would change on an equal percentage basis, and would similarly change on an equal percentage basis with each subsequent distribution revenue requirement change.

Distribution demand and energy charges would also change for each change in the distribution revenue requirement. By contrast, currently, if the distribution revenue requirement changed by 2%, because customer charges were frozen, the distribution demand and energy charges might have needed to increase by 2.5% to achieve the overall class or schedule-level 2% increase. PG&E’s proposal to now include customer charges in this equal percentage increase for interim revenue requirement changes would then allow distribution charges for each of customer, demand, and energy to change by 2%, rather than by 0%, 2.5%, and 2.5%, respectively.

ANSWER 9d

PG&E expects that all implemented distribution revenue requirement rate changes would result in changes to monthly customer charge levels. Even for those customer charges set at or already at full EPMC levels, PG&E proposes to continue to apply equal percentage increases to those customer charges, going forward.





Federation PG&E Witness: Bartman Requester: Karen Mills

QUESTION 11

The following questions concern PG&E’s agricultural customers who do not have interval meters:

a. Please provide the number of such customers by rate schedule and PG&E’s schedule for providing these customers with interval meters.

b. Please provide PG&E’s rate proposal for customers who do not have interval meters for at least 12 months prior to the transition to the new agricultural rate schedules. As part of your response, please clarify whether these customers would remain on legacy AG-1 rates until they have 12 months of interval data and, if so, how the legacy rates would be adjusted for rate design proposals made in this proceeding.

c. Please provide PG&E’s proposal for customers that are migrated to time-of-use rates within 12 months of the transition to the new rate schedules. For example, would the transition to the new rate schedules be delayed for these customers so that they do not have two rate schedule changes within a year, or would the switch to time-of-use rate schedules be delayed until the new rate structures are in place so as to avoid this situation? If the legacy time-of-use rates will continue for a transition period, how will those rates be adjusted for rate design proposals made in this proceeding?

ANSWER 11A

Please see the table below for the number of agricultural customers by rate schedule that do not have interval meters. This table includes customers with solid state meters that are not interval meters but are capable of capturing usage data necessary to bill a specific time-of-use rate.

Agricultural Customers Without Interval Meters

By Rate Schedule October 21, 2016


PG&E does not have a specific schedule, but expects that these 12,119 Agricultural accounts will have interval meters by the end of 2019.


ANSWER 11B

PG&E proposes that customers will remain on legacy rates until they have 12 months of interval data. Please see GRC-2017-PhII_DR_CFBF_002-Q14 for PG&E’s proposed approach for adjusting the legacy rate design to incorporate proposals made in this proceeding.

ANSWER 11C

As explained in Answer 11B above, PG&E proposes that customers will remain on legacy rates until they have 12 months of interval data. PG&E expects to implement the new TOU periods and the new agricultural rate schedules proposed in this proceeding at the same time. Please see GRC-2017-PhII_DR_CFBF_002-Q14 for PG&E’s proposed approach for adjusting legacy rate designs to incorporate proposals made in this proceeding.






QUESTION 13

PG&E-1, p. 7-22 proposes to offer Optimal Billing only on new Schedule AG-C.

a. Please clarify whether PG&E is amenable to retaining Optimal Billing on Schedule AG-5C until that rate schedule is eliminated.

b. If not, please explain why not and please clarify when Optimal Billing would be eliminated on Schedule AG-5C.

ANSWER 13

Yes. PG&E plans to retain Optimal Billing on Schedule AG-5C until the AG-5C rate schedule is eliminated. Optimal Billing would concurrently be made available on the new proposed Schedule AG-C rate schedule once Schedule AG-C is made available.






QUESTION 14

The following questions concern PG&E-1, Appendix B:

a. The proposed rates for AG-A customers are shown to include a Connected Load Charge. However, PG&E-1, page 7-9 states, “PG&E proposes that all legacy and new AG-A customers with an interval meter be billed on the basis of metered kilowatt (kW) rather than the current ‘connected load’ basis.” For customers with interval meters, please clarify whether the Connected Load Charge shown in Appendix B would be applied based on metered load, would be applied based on connected load, or would not be applied, with a different demand charge being applied instead (if so, please specify).

b. Appendix B does not provide proposed rates for the legacy agricultural rate schedules. Given that the legacy schedules will need to continue for an estimated 9-12 months after a decision in this proceeding (per PG&E-1, Table 10-6) and possibly for a longer transition period for certain customers (see question 12 above), please provide proposed rates for each of these schedules and please list any rate design changes that PG&E proposes to implement to the customer charges, demand charges, or energy charges in these schedules upon implementation of the decision in this proceeding and during the period prior to PG&E’s next GRC Phase II decision.

ANSWER 14a

The new Schedule AG-A proposes that a connected load charge of approximately $5.00 per kW would be applied only on an actual measured kW basis. The Exhibit (PG&E-1) page B-23 reference at top under Schedule AG-A currently reads “Connected Load Charge (/hp),” but should instead be changed to read “Demand Charge (/kW).” PG&E expects to continue to use only connected loads on all Legacy Schedule AG-A rates, and only measured kW loads for all new Schedule AG-A billing purposes. Chapter 10, Sections 2 and 3, and Table 10-6, address the transition plan for implementing the new Schedule AG-A demand basis.

Answer 14b

Please see Answers 9 and 12.





Federation PG&E Witness: Bartman Requester: Karen Mills

QUESTION 15

The following questions refer to the timing for implementing the rate changes for agricultural customers in this proceeding (PG&E-1, chapter 10):

a. How does PG&E propose to coordinate the timing for implementing the new TOU periods for agricultural customers with the timing for transitioning customers to new agricultural rate structures? Does PG&E propose to implement both changes at the same time even if this means delaying one of the changes?

b. Please provide sample implementation schedules for transitioning agricultural customers to the new TOU periods and to the new rate structures given a final decision in this proceeding in: (i) December 2017, (ii) March 2018, or (iii) June 2018.

ANSWER 15A

PG&E expects to implement the new TOU periods and the new agricultural rate schedules proposed in this proceeding at the same time.

ANSWER 15B

PG&E expects that the new TOU periods and new Ag rate schedules will be available

for opt-in nine to twelve months from a final decision.1

Six to nine months later, all eligible agricultural customers will be transitioned to the new TOU periods and new Ag

rate structures.2

Please see table below for sample implementation schedules for transitioning agricultural customers to the new TOU periods and the new rate structures.

1 See Exhibit I, 10-26, Lines 5-7. 2 See Exhibit I, 10-22, Lines 17-20.


Sample Implementation Schedules 2017 GRC Phase 2 TOU periods and Ag Rate Schedule Proposals

Final Decision New TOU Periods and new Ag rate

schedules available for opt-in

(9 to 12 months from Decision)

Earliest Transition

(6 to 9 months from opt-in availability)

December 2017 September 2018 – December 2018

March 2019 – September 2019

March 2018 December 2018 – March 2019

June 2019 – December 2019

June 2018 March 2019 – June 2019

September 2019 – March 2020




PG&E Data Request No.: CFBF_003-Q03 PG&E File Name: GRC-2017-PhII_DR_CFBF_003-Q03 Request Date: December 2, 2016 Requester DR No.: 003 Date Sent: December 12, 2016 Requesting Party: California Farm Bureau


QUESTION 3

Footnote 11 (p. 7-14) of PG&E-1 states, “PG&E is not proposing to adjust distribution and generation demand and energy charges for the legacy agricultural rates schedules” (PG&E-1, p. 7-14, footnote 11). However, the top of p. 7-17 in this same volume of testimony states that the “equal cents” approach will be used to apply revenue requirement changes to generation rates in the legacy rate schedules.

a. Please clarify whether the distribution and generation demand and energy charges for the legacy agricultural rates schedules will be adjusted for revenue requirement changes upon implementation of this GRC and upon revenue requirement changes between this and the next GRC.

b. If the answer to part a. is yes, please clarify what is meant by footnote 11 of PG&E-1.

c. If the answer to part a. is yes, please identify any ways in which the methodology for adjusting the legacy agricultural rate schedules will differ from the methodology outlined in PG&E-1, Chapter 1, Attachment B.

d. Please identify any circumstances under which the legacy time-of-use (TOU) rate schedules would be adjusted to reflect the new TOU periods that are adopted in this proceeding.

ANSWER 3a

Yes, distribution and generation demand and energy charges for the legacy agricultural rates schedules will be adjusted for revenue requirement changes upon implementation of this GRC and upon revenue requirement changes between this and the next GRC. This adjustment will be limited to equal percent or equal cents adjustments, as applied to status quo legacy agricultural rate schedules, with two limited exceptions.


First, PG&E generally proposes PPP adjustments in all customer classes, as addressed in PG&E’s December 2, 2016 Updated and Amended testimony,Exhibit (PG&E-8), Volume 1, Chapter 1, at pp. 1-8 to 1-9, and Chapter 3 at pp. 3-5 to 3-6.1

Second, PG&E proposes a modification to current or prior equal percent changes between GRCs, to immediately also include legacy fixed monthly customer charges among the elements subject to interim equal percent changes, for distribution revenue requirement changes, and to use equal cents methods rather than the equal percent approach where appropriate for all distribution and generation component rate changes.

ANSWER 3b

Footnote 11 on page 7-14 of the agricultural rate design chapter is intended to clarify that no fundamental redesign of legacy distribution or generation rate components is proposed to be revised by PG&E. No updated cost-based TOU rate levels, TOU ratios, seasons, TOU hours, such as on-peak versus off-peak TOU hours, demand versus energy splits, or other underlying rate design methods will be revised for legacy agricultural rate schedules. Instead, all legacy agricultural rates will use status quo rate designs, and merely be adjusted going forward to change using equal percent or equal cents revisions for revenue requirement changes, almost as though the 2017 GRC Phase 2 case did not take place, with the PPP, customer charge, and equal cents exceptions noted in Answer 3a.

In contrast, PG&E proposes that all new cost-based TOU seasons, TOU hours, demand charges, and energy charge levels apply only to the proposed new series of Schedules AG-A, AG-B, and AG-C. The new Schedule AG-A, AG-B, and AG-C rates would similarly be subject to equal percent or equal cents changes upon or after implementation, as illustrated in PG&E’s response to CFBF_002-Q09a-Atch01.

ANSWER 3c

Chapter 1, Attachment B, at paragraph g, lines 23 to 26, notes that non-residential equal percent changes will be applied to customer, demand, and energy charges unless otherwise addressed in specific chapters. In agricultural Chapter 7, PG&E addresses specific interim rules to apply to both legacy rates and the new agricultural rates. For example, see Exhibit (PG&E-8), Volume 1, Chapter 7, p. 7-14, lines 1 to 3, and 10 to 12; p. 7-15, lines 21 to 24; and p. 7-16 line 23 to p. 7-17 line 3.

ANSWER 3d

As noted above, under PG&E’s proposal, the ten legacy agricultural rate schedules would not be adjusted to reflect the new TOU periods that are adopted in this proceeding. Those rates will be supplanted by the new consolidated Schedule AG-A, AG-B, and AG-C rates with updated TOU periods, and when customers are transitioned 1 On December 2, 2016, PG&E served its Updated and Amended testimony, Exhibits

(PG&E-8) and (PG&E-9), which supersede and replace Exhibits (PG&E-1) and (PG&E-2), respectively.


off the legacy rates, the legacy rates would be closed and would never be adjusted to reflect the new TOU periods.





Federation PG&E Witness: Emily Bartman Requester: Karen Mills

QUESTION 4

PG&E-1, page 10-22, states that the default transitions to the new TOU periods would be aligned, “to the extent possible, with existing November SMB and March Ag transition windows.” PG&E’s response to Data Request CFBF 2, Q.15 provides sample implementation schedules for Ag customers that span every month of the year.

a. Please clarify whether it is PG&E’s intent to implement the new TOU periods and new rate schedules for Ag customers during March.

b. Please specify the circumstances under which the new TOU periods and new rate schedules for Ag customers would be implemented in months other than March.

c. If the default implementation were to occur, for example, in June 2019, which TOU period definition (current vs. new) would be implemented for a customer that is transitioned from AG-1 rates to TOU rates in March 2019? (Please specify which TOU period would be implemented in March 2019 and which would be implemented in June 2019.)

d. If the new TOU periods were to become available on an opt-in basis, for example, in September 2018, which TOU period definition (current vs. new) would be implemented for a customer that is transitioned from AG-1 rates to TOU rates in March 2018? (Please specify which TOU period would be implemented in March 2018 and which would be implemented in September 2018.)

ANSWER 4A

Yes, PG&E prefers to implement the new rate schedules with updated TOU periods for Ag customers on a default basis in March, to align with TOU default and during an inactive period for most Ag customers.

ANSWER 4B

PG&E does not currently anticipate any circumstances where the new rate schedules for Ag customers would be implemented on a default basis in months other than March.


ANSWER 4C

If default implementation is possible in June 2019 because billing system changes are complete, and rates with new TOU periods have been available on an opt-in basis for six to nine months, AG-1 customers with 12 months of interval data would be transitioned to the new time periods in March 2020, along with all other AG customers being defaulted to the new TOU time periods. No default of AG customers to TOU rates (either legacy TOU rates or rates with new TOU periods) would occur between June 2019 and February 2020.

ANSWER 4D

If, as CFBF’s hypothetical question postulates, the new rates with the updated TOU period definition were to become available on an opt-in basis in September 2018, any AG-1 customers transitioned to TOU previously, in March 2018, would have been transitioned to the legacy rates with the current TOU period definition (Noon – 6pm peak).

Between September 2018 and the end of February 2019, the only customers that would move from the legacy rate to the new rates with the updated TOU period definition (5pm – 10pm peak) would by those customers who affirmatively choose to opt-into one of the new rates.

However, PG&E does not believe these hypothetical timeframes are likely to apply. PG&E believes a final decision on the 2017 GRC Phase II is likely to be issued in Q1 2018, followed by up to 12 months of billing system programming implementation time (to Q1 2019), followed then by up to 9 months of opt-in-only availability of the new rates (end of 2019). Therefore, the earliest likely implementation for these new rates on a default basis appears to be March 1, 2020.






QUESTION 6

Please provide a description of any outreach and education which PG&E has conducted for its customers in general, or specific to the agricultural class, to explain how TOU periods are changing from the current default TOU periods. Please also provide copies of any materials, which have been furnished to customers.

ANSWER 6

PG&E has not yet conducted any broad outreach and education for non-residential customers regarding how TOU periods are changing from the current default TOU periods.

PG&E has introduced the concept of TOU time periods changing (and peak periods moving later in the day) in customer workshops in late 2015 that were part of the Ag Collaborative process which resulted from the 2014 GRC Ag Party settlement agreement.

Education and outreach on later peak periods has also been conducted:

a) Among residential customers, including customers transitioning from sunsetting Schedule E-7 who could choose E-6 (now closed to new customers) or E-TOU-A (3pm – 8pm peak moving to 4pm – 9pm on January 1, 2020), or E-TOU-B (4pm – 9pm peak, no baseline credit)

b) Among residential customers who were offered participation in PG&E’s residential Opt-In TOU Pilot, which has three different rate options with later time periods:

Pilot Rates 1 and 3: 4 p.m. to 9 p.m. Pilot Rate 2: 6 p.m. to 9 p.m.

The outreach for the Opt-in TOU Pilot rates is described in Advice 4764-E, filed December 24, 2015, Chapter 11.

c) Education and Outreach is also planned for the residential Default TOU Pilot in 2018. Details will be available in PG&E’s December 16, 2016 advice filing providing the Residential Default Pilot plan.




PG&E Data Request No.: CFBF_004-Q02 PG&E File Name: GRC-2017-PhII_DR_CFBF_004-Q02 Request Date: January 4, 2017 Requester DR No.: 004 Date Sent: January 30, 2017 Requesting Party: California Farm Bureau

Federation PG&E Witness: Tysen Streib Requester: Karen Mills

QUESTION 2

The table below shows the annual average number of agricultural customer accounts per three PG&E datasets:

Dataset A: "Sales Customer Forecast versus Actuals 10 Years.xlsx" (in workpapers to Appendix F Ag Balancing Account Study, folder “Workpapers - Sales and Total Rate Variance”), sheet “Customers Annual,” column E (total customer-months divided by 12 to obtain annual average customer accounts shown in the table)

Dataset B: "Attachments 5_6_7_Corrected_p.xlsx" (in workpapers to Appendix F Ag Balancing Account Study, top-level folder), sheet “2014 DistMC Summary,” column M (total customer-months divided by 12 to obtain annual average customer accounts shown in the table)

Dataset C: PG&E response to CFBF Data Request 3 Q 2, Attachment 1, sheet “2A,” column C


a) Please explain the differences between the customer account numbers for 2013 shown in each of the three datasets.

b) Please explain the significant difference between the customer account numbers shown in Dataset C and the customer account numbers shown in the other datasets.

c) Please provide the annual average number of agricultural electric accounts in each year from 1995-2016.

ANSWER 2

a) During investigation into this data request, PG&E discovered dataset C provided in response to CFBF_003-Q02 was incorrect. The text incorrectly stated that PG&E used customer rate schedule as of December, and then back cast as though each customer had only been on that December rate schedule all year, in the prior 11 months. Instead, PG&E inadvertently did not apply that December rate schedule screen. As a result, PG&E inadvertently captured all intra-year rate schedule migration activity by individual customers, often double-counting the same customer or meter site within the same calendar year. This was primarily due to the following factors:

Default TOU activity, in which AG-1A and AG-1B customers in January and February migrated to AG-4A and AG-4B in March.

Voluntary rate schedule migration, such as when a grower may decide to switch many of his current AG-5B meter sites to AG-4B, based on analysis as he was approaching the growing season, and planning lower irrigation volumes than in prior years.

PG&E interval meter installations which change the SAID (Service Agreement ID) for a given meter site, or other reasons an SAID might change, such as a change in meter reading route.

The SAID changed due to a change of party, new ownership, or new account title holder on the meter site, among others.


In addition, the customer counts for dataset A were low for 2013 because the reported number of customer months only included data through October 2013, as described in the answer to Question 1, part a.

b) See the answer to part a.

c) Below is a table showing the average number of monthly bills in Revenue Account 354 (Agricultural) from 2003 to 2016.

Year Average Monthly Bills 2003 81,029 2004 79,886 2005 79,097 2006 79,331 2007 80,644 2008 81,956 2009 83,639 2010 83,812 2011 84,133 2012 85,628 2013 85,541 2014 86,825 2015 88,016 2016 88,668




PG&E Data Request No.: CFBF_004-Q03 PG&E File Name: GRC-2017-PhII_DR_CFBF_004-Q03 Request Date: January 4, 2017 Requester DR No.: 004 Date Sent: January 30, 2017 Requesting Party: California Farm Bureau

Federation PG&E Witness: Tysen Streib Requester: Karen Mills

QUESTION 3

PG&E workpaper "Attachments 5_6_7_Corrected_p.xlsx" (in workpapers to Appendix F Ag Balancing Account Study, top-level folder), provides actual agricultural generation and distribution PCAFs and FLTs in each of the years 2011-2014 (see sheet “2014 DistMC Summary,” columns J and L, and sheet “2014 GenMC Summary,” Column I)

a) Please identify the source of each year’s data (e.g., load research data, smart meter data, etc.).

b) Please provide the list of peak intervals (i.e., peak hours or peak 15-minute intervals, as applicable) that are included in the generation and distribution PCAFs for each of the years 2011-2014.

c) Please provide actual agricultural generation and distribution PCAFs and FLTs consistent with those provided in this workpaper for each of the years 1995-2010, along with a list of the peak intervals included in each set of PCAFs. If PG&E is unable to provide data from each of these years, please provide the available data.

ANSWER 3

a) The data is from load research data for all years and includes SmartMeter data starting in 2012.

b) This data is provided in GRC-2017-PhII_DR_CFBF_004-Q03_Atch1.xlsx.

c) Confidential, provided pursuant to P.U Code Section 583, the California Public Records Act and the NDA for PG&E 2017 GRC II. This data response includes Proprietary and/or Confidential material exempt from disclosure to the public or third parties, including under the Public Records Act, and is being provided under the provisions of G.O. 66-C, Public Utilities Code Section 583, and as a trade secret pursuant to California Civil Code Sections 654, 655 and 3426- 3426.10 . In addition, certain material contains customer information that is confidential because does not meet the 15/15 aggregation requirements for protection of the privacy of non-residential customers and/or the 100/zip code aggregation requirement for protection of the privacy of residential customers under D.14-05-016 and other CPUC and California privacy rules and requirements.


The confidential file GRC-2017-PhII_DR_CFBF_004-Q03_Atch2_CONF.xlsx contains FLT data from 1999 to 2010.

The file GRC-2017-PhII_DR_CFBF_004-Q03_Atch3.xlsx contains distribution PCAFs from 1999 to 2010.

The file GRC-2017-PhII_DR_CFBF_004-Q03_Atch4.xlsx contains generation PCAFs from 2002 to 2010.




PG&E Data Request No.: CFBF_006-Q01 PG&E File Name: GRC-2017-PhII_DR_CFBF_006-Q01 Request Date: January 30, 2017 Requester DR No.: 006 Date Sent: February 15, 2017 Requesting Party: California Farm Bureau

Federation PG&E Witness: Amitava Dhar Requester: Karen Mills

QUESTION 1

PG&E’s responses to DR 5 provided the same FLT data in response to our requests for both peak demand data (Q1) and non-coincident load data (Q2), but we were asking for two different sets of data. We can use the FLT data in response to Q2 (non-coincident load), but we’d like the generation PCAF data in response to Q1 (annual peak demand by class from 1995-2016, by division if available).

ANSWER 1

The generation PCAF data that PG&E currently has available only cover 2002 through 2015. Please find attached the data in file “GRC-2017-PhII_DR_CFBF_006-Q01 Atch01.xlsx”.




PG&E Data Request No.: CFBF_007-Q01 PG&E File Name: GRC-2017-PhII_DR_CFBF_007-Q01 Request Date: February 13, 2017 Requester DR No.: 007 Date Sent: March 1, 2017 Requesting Party: California Farm Bureau


QUESTION 1

With regard to each mandatory transition of agricultural customers to time-of-use rates since the mandatory transition began:

a. Please provide the date (i.e., month and year) of each transition, and

b. Please provide the number of (i) AG-1-A and (ii) AG-1-B customer accounts that were transitioned on a mandatory basis at each transition date.

ANSWER 1

Please see Table 1 below for the requested data for each year from 2013 - 2017

Table 1 Mandatory Transitions of Agricultural Customers to TOU rates (2013 – 2017)

Transition Month (a) From To

Number of Customer Accounts Transitioned

(b)1

March 2013 AG-1A AG-4A2 17,582

AG-1B AG-4B 578

March 20143

AG-1A AG-4A 0 AG-1B AG-4B 0

March 20154

AG-1A AG-4A 5,125 AG-1B AG-4B 2,525

March 2016 AG-1A AG-4A 1,341 AG-1B AG-4B 494

March 2017 AG-1A AG-4A 612 AG-1B AG-4B 249

Total AG-1A AG-4A 24,660 AG-1B AG-4B 3,846

28,506

1 Figures above are taken from Annual Electric True-Up or other PG&E advice letters to implement the annual agricultural default TOU revenue neutral after-the-

fact adjustments authorized in D.11-12-053 and D.15-08-005, except that March 2017 figures are a preliminary estimate. March 2014 figures are from

analysis supporting Energy Division’s report on the March 2014 customer letter notification issue.

2 The main destination TOU rate schedules were AG-4A and AG-4B. However, a small number and/or small percentage of customers in each transition window

migrated to other agricultural rates, such as AG-5A, AG-5B, AG-4C, and AG-5C.

3 Automatic transition process was halted in 2014 to prevent agriculture customers from moving to new TOU electric rates without the proper notification.

Transition of 3,764 AG-1A and 911 AG-1B was delayed until March 2015.

4 The number of transitioning customers in 2015 includes the 3,764 AG-1A and 911 AG-1B customers that would have transitioned in 2014.






QUESTION 2

Please provide the number of customers remaining on AG-1-A and AG-1-B tariffs as of February 2017 (or the most recent prior date for which these data are available).

ANSWER 2

As of December 2016, there were 3,452 customers on the AG-1-A and 2,116 customers on the AG-1-B rate schedules.






QUESTION 3

Please provide PG&E’s projected schedule for transitioning remaining AG-1-A and AG-1-B customers to time-of-use rates.

ANSWER 3

Twelve months of interval data is required to transition non-CCA/DA AG-1-A and AG-1-B customers to TOU rates, as ordered by D. 11-11-008 and D.10-02-032.1 As of late February, 2017, 27,645 AG 1-A and AG-1-B customers have been transitioned to TOU rates, with 5,561 remaining on flat rates. An AG-1-A or AG-1-B customer remains on a flat rate for one of three reasons: 1) an interval meter is installed, but has not yet transmitted twelve months of interval data, 2) a legacy meter is installed that does not capture or transmit interval data, or 3) they are a CCA/DA customer. Some CCA/DA AG-1-A and AG-1-B customers already have twelve months of interval data and will be transitioned subject to CPUC approval in this GRC Phase 2 proceeding, while some fall in to category 1 and 2 above. The SmartMeter mesh network is considered to be “green” when SmartMeters installed in that area are successfully transmitting data. Legacy meters with “green” SmartMeter network area are prioritized for replacement. Those legacy meters in “amber” and “red” network locations will either move to “green” status as the SmartMeter mesh network continues to strengthen, or will be addressed with other solutions as described in GRC-2017-PhI_Test_PGE_20160527-Exh25-Vol-I-Ch07, by the end of 2018, allowing the majority to transition to TOU with twelve months of interval data in March of 2020. Please see the table below for the number of service points with meters in each category, and PG&E’s transition plan.

1 PG&E has proposed to transition flat rate CCA/DA Small/Medium Business and Agricultural

customers to TOU rates in this 2017 GRC Phase 2 application. PG&E anticipates, with a GRC Phase 2 decision in first quarter of 2018, that CCA/DA flat rate agricultural customers with twelve months of interval data will be transitioned to TOU rates in March of 2019.


AG-1A and AG-1B

Flat Rate Customers

Number of Service Points

TOU Transition Plans

1) Interval meter installed and transmitting data for less than 12 months

Non-CCA/DA

2,393 PG&E anticipates 851 these customers will transition to TOU in March of 2017. The remaining 1,542 are expected to transition to TOU with 12 months of interval data in March of 2018.

2) Legacy meter Non-CCA/DA

1,717 70% of these meters are in “green” network areas. PG&E plans to replace these meters with interval meters by the end of 2017, allowing transition to TOU with twelve months of interval data in March 2019. The remaining 30% of meters (“amber” or “red” areas) will either move to “green” status as the SmartMeter mesh network continues to strengthen, or will be addressed with other solutions as described in GRC-2017-PhI_Test_PGE_20160527-Exh25-Vol-I-Ch07, by the end of 2018, allowing the majority to transition to TOU with twelve months of interval data in March of 2020.

3a) CCA/DA Interval Meter

1,259 Subject to 2017 GRC 2 decision authorization, PG&E anticipates transitioning these customers to TOU rates the first March that falls at least 60 days after the decision. 60 days is needed for required customer notification. For example, with a December 2017 decision, these customers would transition in March of 2018. With a decision in early 2018, these customers would transition in March of 2019.

3b) CCA/DA Legacy Meter

192 75% of these meters are in “green” network area. PG&E plans to replace these meters with interval meters by the end of 2017, allowing transition to TOU with twelve months of interval data in March 2019. The remaining 25% of meters (“amber” or “red” areas) will either move to “green” status as the SmartMeter mesh network continues to strengthen, or will be addressed with other solutions as described in GRC-2017-


PhI_Test_PGE_20160527-Exh25-Vol-I-Ch07, by the end of 2018, allowing the majority to transition to TOU with twelve months of interval data in March of 2020.

Total 5,561




PG&E Data Request No.: CFBF_007-Q05 PG&E File Name: GRC-2017-PhII_DR_CFBF_007-Q05 Request Date: February 13, 2017 Requester DR No.: 007 Date Sent: February 23, 2017 Requesting Party: California Farm Bureau

Federation PG&E Witness: Keith Coyne,

Emily Bartman Requester: Karen Mills

QUESTION 5

Please provide the presentations dated January 30, 2017 and February 3, 2017 that PG&E provided for the Agricultural Collaborative Rate Design Framework discussions.

ANSWER 5

Please see the attachment “GRC2017-Ph-II_DR_CFBF_007-Q05-Atch01.ppt” for the PowerPoint slide deck presented during the January 30, 2017 Agricultural Collaborative Rate Design conference call, as well as earlier such calls. This material includes summary comparisons of legacy agricultural rates to proposed new consolidated agricultural rates, rate option features, alternate illustrative generation and total rate design examples for successor split-week Schedule AG-R, based on both legacy AG-R and class level billing determinants, illustrative bill impacts of a proposed agricultural Demand Charge Limiter (DCL) of $1 and $0.50 per kWh on the three new basic proposed rates, and the frequencies of customers protected by the DCL.

Please see the attachment “GRC2017-Ph-II_DR_CFBF_007-Q05-Atch02.ppt” for the PowerPoint slide deck that was the main topic of, and introduced for the first time at, the January 30, 2017 Agricultural Collaborative Rate Design conference call. Atch02 summarized PG&E’s proposed plan (Exhibit I, Chapter 10, at pages 10-22 to 10-25) for transitioning non-residential customers to the new proposed TOU and PDP time periods.

Please see the attachment “GRC2017-Ph-II_DR_CFBF_007-Q05-Atch03.ppt” for the follow-up PowerPoint slide deck dated February 3, 2017 that was transmitted via e-mail on February 7, 2017. This material was limited to supplemental statistics broken down by new rate schedule of the frequencies of customers protected by the DCL.

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BEFORE THE PUBLIC UTILITIES COMMISSION OF THE

STATE OF CALIFORNIA

(Filed April 18, 2013)

TESTIMONY OF

DR. BARBARA R. BARKOVICH AND CATHERINE E. YAP

ON MARGINAL COSTS, REVENUE ALLOCATION AND RATE DESIGN

ON BEHALF OF THE

CALIFORNIA LARGE ENERGY CONSUMERS ASSOCIATION

AND THE

CALIFORNIA MANUFACTURERS AND TECHNOLOGY ASSOCIATION

December 13, 2013

equipment were not in place, the customer would have to obtain new customer-

access equipment.

Q94. Do you recommend the use of the RECC method in this proceeding?

A94. Yes. We do not support the NOC/OTHC methodology because it ignores

hundreds of millions of dollars of investment in customer plant and equipment,

investment which is concentrated in the numerically large residential and small

commercial classes, and thereby distorts the allocation of overall revenue

requirement among the classes.

Q95. Have you developed marginal customer costs using the RECC method in this

proceeding and used them in your revenue allocation?

A95. Yes. PG&E’s model enables the use of the RECC method in performing the

distribution allocation. We have used the RECC method in developing our

recommended cost allocation.

III. REVENUE ALLOCATION

A. Background

Q96. Please describe the process of marginal-cost based revenue allocation.

A96. Revenue allocation is the process by which revenue responsibility for the utility’s

entire revenue requirement is assigned among groups of the utility’s customers.

Bundled customers are assigned responsibility for a share of all utility costs. DA

and Community Choice Aggregation (CCA) customers are assigned

responsibility for a share of all delivery costs and “non-bypassable costs”, but not

for generation costs incurred by the utility to serve its bundled customers.25

25 This is true except for the Cost Responsibility Surcharge for DA and CCA customers, which is not an

issue in this proceeding, and the Competition Transition Cost (CTC), which is charged to all customers,

Delivery costs include transmission, distribution, and appropriate customer costs.

Thus the process of revenue allocation is one of dividing up responsibility for the

utility’s revenue requirement between bundled and DA/CCA customers and then

among all the customer classes covered by the utility’s tariffs. A revenue

allocation may also allocate directly to rate schedules within the class. Since the

Commission has endorsed marginal-cost ratemaking for decades, marginal costs

are used to perform the revenue allocation.

Q97. What are marginal cost revenue responsibilities (MCRRs) and how have they

been determined in the past?

A97. Historically, the MCRR for each customer class (or rate schedule) was the

product of the usage pattern associated with each type of marginal cost

multiplied by that marginal cost, aggregated for each class across all marginal

costs. The MCRR for each class represents its share of the total MCRR. The

total utility revenue requirement was then divided by the total MCRR across all

the classes. This created a multiplier (i.e., a ratio), called the EPMC multiplier,

that was applied to the MCRR for each class to create its allocated revenue

requirement.

Q98. How are the MCRRs currently developed?

A98. Since the Commission instituted unbundling, there are now subsets of MCRR,

one for generation and one for distribution/customer costs. It is no longer

appropriate for delivery costs to be allocated to DA or CCA customers using an

including some Departing Load (DL) customers, but is included in the Indifference Fee part of the CRS for DA and CCA customers.

allocator that includes generation. It is also no longer appropriate for costs to be

allocated using transmission costs that are separately allocated by the FERC.

Marginal generation costs for bundled customers are the sum of the

product of customer demand by class for each TOU period times the MGCC for

that TOU period plus the kWh usage for each TOU period for that class times the

MEC for that time period. Thus, each class of bundled customers will have a

percentage share of the marginal generation costs. The total marginal generation

cost revenue is then divided into the generation revenue requirement to create a

generation “EPMC” multiplier, which can be applied to the marginal cost revenue

responsibility for each bundled class to determine its allocated share of the

revenue requirement for generation.

Marginal costs of distribution and customer access are allocated on a

combined basis, excluding the FERC regulated transmission costs. First, the

marginal distribution capacity cost is multiplied times the relevant demand for

each class using PG&E’s PCAFs, which relate to localized peak demands on the

local distribution system.26 This creates the marginal distribution capacity

revenue responsibility. Second, under PG&E’s methodology, which we do not

support, the NCO/OTHC method is applied to determine the marginal customer

cost revenue responsibility for each class.27 The MCRRs for distribution and

customer costs are combined for each class. The total MCRR for each class is

then multiplied by the ratio of the revenue requirement for distribution and

26 These PCAF-related demands are then sorted into the traditional TOU periods. 27 Under this method, the customer access marginal cost is multiplied by the number of new customers for

each class and the cost of providing customer and billing service by class is multiplied by the total number of customers, creating the marginal customer-related revenue requirement. It is discussed further below.

customer access costs divided by the system-wide MCRRs for distribution and

customer costs, creating a distribution/customer EPMC factor. The EPMC factor

is then applied to the marginal cost revenue responsibility for each bundled class

to determine its allocated share of the distribution/customer revenue requirement.

Q99. The allocation of which costs do you address in your testimony?

A99. We address the allocation of generation costs, distribution and customer costs,

transmission costs, and certain other miscellaneous costs that are considered non-

bypassable. These costs are often referred to as “cats and dogs” since they do not

fall neatly into the categories of generation, transmission, and distribution. We

should note that these costs, despite being harder to functionalize than generation

contracts or distribution plant, represent hundreds of millions or even billions of

dollars and their allocation should be taken very seriously.

B. Allocation of Generation Costs

Q100. Which costs are included in this allocation of generation costs?

A100. Generation costs include the costs of PG&E generating facilities and power

purchased under contract. They include costs of facilities and running costs. For

marginal cost purposes, these costs are divided into MGCCs and MECs.

Q101. How does PG&E propose that generation costs be allocated?

A101. PG&E uses its PCAF methodology to allocate marginal generation capacity

costs.

Using the system PCAF method, PG&E has estimated each class’ average contribution to the system peak during a recorded three year period. These recorded kW values are converted to forecast system PCAF weighted loads by multiplying them by the ratio given by TY sales divided by recorded sales. The class’ TY marginal generation capacity cost revenue equals the class’ system PCAF weighted loads

for the TY, times the marginal generation capacity cost (including the 15 percent planning reserve requirement adjustment) from Exhibit (PG&E-5), Chapter 2, “Marginal Generation Costs.” (PG&E-4, p. 2-11.)

PG&E allocates energy-related costs on the basis of TOU energy use by

class. “To calculate a class’ marginal energy cost revenue, PG&E first assigns the

forecast sales among five TOU periods using the class’ recorded TOU usage

pattern. The TY marginal energy cost revenue for a given TOU period equals the

marginal energy cost for that period multiplied by the forecast sales in the period.

Total marginal energy cost revenue for the class equals the sum of the marginal

energy cost revenue across the five TOU periods.” (Ibid., p. 2-12, footnote

omitted.)

Q102. How does ORA propose to allocate generation marginal cost revenues?

A102. ORA uses the same methodology as PG&E in calculating marginal cost

generation revenues. However, as noted previously, ORA makes changes to both

the MGCC and the MECs. (ORA, p. 4-4.)

Q103. Do you agree with PG&E’s methodology of allocating marginal generation

capacity costs?

A103. No, we do not. Specifically, PG&E uses its PCAFs to allocate generation

capacity costs. It states:

The PCAF methodology addresses the fundamental uncertainty of using peak load responsibility for a single recorded hour to forecast future class level responsibility by considering the cost responsibility across a broader group of the highest recorded load hours, while still assigning significantly greater weights to those hours with the very highest loads. PG&E developed and began using its generation PCAF methodology starting in the 2003 GRC, when the older LOLP-based allocators were no longer readily available (as a consequence of changes associated with electric industry restructuring). The format that PG&E selected for these generation PCAF calculations is exactly

the same as those it has used for distribution-level PCAFs ever since their first introduction in PG&E’s 1993 GRC. (CLECA-05, Q.5.4.4.)

PCAFs are an aggregate measure of demand pressure created by local load

on distribution level facilities. PCAFs are defined as the loads that exceed 80% of

the local distribution capacity:

“PG&E estimates class loads at the substation level using weighting factors called “peak capacity allocation factors” (distribution PCAF) FN6 and at the final line transformer (FLT) level. FN 6: The substation PCAF-weighted loads are weather-normalized weighted loads that indicate what contribution a class has made to a substation’s peak.” (PG&E, p. 2-7 A. 06-03-005.)

and

PG&E estimates class loads at the substation level using weighting factors called “peak capacity allocation factors” (distribution PCAF) and at the final line transformer (FLT) level. (PG&E-4, p. 2-8, footnote omitted.)

PG&E aggregates the PCAFs measured at the distribution level into

“system-wide” PCAFs, which it then uses to allocate generation MCRRs. “PCAF

hours are selected as those hours in which the load exceeds 80 percent of the

single hour maximum demand at the generation level across PG&E’s service area.

The number of hours exceeding this threshold will vary from year to year.”

(CLECA-05, Q.5.4.1.)

PCAFs do not take into account the availability of generation capacity to

serve that load. They are a measure of load at the distribution system level.

Historically, loss-of-load probability (LOLP) was calculated and used as a

measure of the combination of system load plus the availability of generation to

meet that load. As a result, there was some LOLP during the winter, when plants

were out for maintenance. PCAFs do not address this issue.

In the last four PG&E GRC Phase 2 proceedings, we stated that we

believed that PG&E should be required to produce LOLPs or LOLEs for its next

GRC and that these LOLPs/LOLEs should be used to allocate MGCCs. We have

asked for these data in data requests in prior proceedings and PG&E responded

that it did not do this type of modeling. In this proceeding, PG&E produced

LOLEs from its 2006 LTPP filed on March 5, 2007, in response to CLECA Data

Request 5. Question 5.4.8. “The LOLP study PG&E currently uses internally and

has referred to in various CPUC proceedings is a consultant study submitted by

PG&E in its 2006 Long Term Procurement Plan Proceeding. The modeled year

was 2014.” (CLECA-05, Q.5.4.8.) Apparently, this is PG&E’s only such study

performed since 2003. (Ibid.)

We note here that SCE allocated its MGCC using LOLP/LOLE in its Test

Year 2006, 2009, and 2012 Phase 2 proceedings and believe that PG&E should be

required to do the same. PG&E should be required to produce forward-

looking LOLP/LOLE data as part of its regular Phase 2 filings as well as a

forecast of future loads by class and rate schedule and TOU period (in kW,

not kWh). PG&E also should be directed by the Commission to compare the

results of such an allocation of generation-related marginal cost revenues to

those it achieves using PCAFs and to make this study available for review by

parties. Only in this way will it be possible to validate PG&E’s decision to

allocate generation costs using loads on the distribution system.

If the LOLP/LOLE and class and rate schedule TOU load data were

available, we would create a generation marginal cost revenue responsibility by

assigning MGCC to class and rate schedule by TOU periods using LOLP/LOLE

instead of PCAFs. For the purposes of this proceeding, however, we have been

forced to use the PG&E methodology, including PCAFs. However, we assert yet

again that PCAFs are not an appropriate measure of system load as it relates to the

need for generation and PG&E should be required to develop LOLP/LOLE for

future GRCs.

Q104. How do you propose to allocate generation costs?

A104. Generation marginal costs (both energy and capacity) should be used to develop

a marginal cost revenue responsibility (MCRR) to allocate all generation-related

costs. These would include costs related to all the generation resources used to

serve PG&E’s bundled customers. They should also include costs associated

with nuclear decommissioning since these are also generation-related.

Q105. Do PG&E and ORA agree with your proposal to use this method to allocate the

costs of all of PG&E’s generation resources?

A105. Yes, for generation costs. Each has proposed an allocation of generation-related

costs based on generation-related marginal costs.

Q106. Based on your marginal cost testimony, what do you use as the measure of the

MGCC?

A106. We use a six-year levelized cost of a CT, as discussed in our marginal cost

testimony above, which is $224.62/kW-year. We agree with PG&E’s proposal

for a 15% adder to the MGCC for revenue allocation purposes to reflect the fact

that the utility must maintain a 15% Planning Reserve Margin.

Q107. What do you recommend as MECs for performing the revenue allocation?

A107. We recommend the MECs set forth in our Table 2.

C. Allocation of Marginal Distribution and Customer Costs

Q108. What are the central issues regarding allocation of marginal distribution and

customer costs in this case?

A108. Marginal distribution and consumer costs are allocated together on an EPMC

basis. The most controversial issue is the allocation of MCCs. PG&E and ORA

recommend allocation of MCC on the basis of the OTHC/NCO method, although

they have certain differences in how they define these MCC (e.g., data to develop

these costs). The other controversial issue is what forecast of new customers

should be used for this allocation.

Q109. Have you used the OTHC/NCO method for allocating marginal customer costs in

your revenue allocation?

A109. No. PG&E’s model incorporates an option to utilize the RECC and, as we

discussed in the section on MCC, we believe that the RECC method is the correct

method to use.

We believe that the OTHC/NCO method creates a very fundamental

mismatch between the indicated marginal cost of hooking up customers to the

system and the actual cost of providing and maintaining the facilities to provide

customers with a connection to the system – the theory simply does not begin to

match the reality.

Under the OTHC/NCO method, the cost of a new hookup is allocated to a

customer class based on the number of new customers forecast to be added to the

class during the test year. The result of this approach is that a class with

significant load growth but a relatively small established base of customers

receives an out-sized allocation.

D. Allocation of Transmission Revenue Requirement

Q110. How do you propose to allocate the transmission revenue requirement?

A110. The FERC determines the allocation (and rate design) for unbundled

transmission costs for PG&E. These FERC-approved values are used in our

revenue allocation and rate design.

E. Allocation of Other Revenue Requirement Components

Q111. Please explain how PG&E has proposed to allocate other revenue requirement

components, including Public Purpose Programs (PPP), Nuclear

Decommissioning (ND), CTC, the California Solar Initiative (CSI), Self-

Generation Incentive Program (SGIP), Demand Response, interruptible

incentives, CARE, and costs associated with implementation of dynamic pricing.

A111. PG&E proposes the following allocations for the various cost categories:

EPIC and LIEE/EE: equal percentage change to current revenue (EPR)

CARE: equal cents per statute except for CARE and street lighting customers

FERA: equal cents per kWh within residential class

DWR BOND: equal cents per kWh

ND: equal cents per past Commission decision

ECRA: equal cents per past Commission decision

CTC: top 100 hours per past Commission decision

A131. We provide a summary of our revenue allocation below in Tables 4A and 4B,

which provides a comparison with PG&E’s and ORA’s revenue allocations.

Table 4A: Comparison of Allocation for Bundled Customers

CLECA PG&E ORA Class Present Rate

Revenues ($000)

Total Revenue ($000)

Percent Change


Percent Change


Percent Change

Residential 5,309,098 5,450,984 2.7 5,240,212 -1.3 5,155,126 -2.9 Small L&P 1,613,914 1,629,646 1.0 1,603,555 -0.6 1,491,745 -7.6 Medium L&P 1,239,695 1,194,036 -3.7 1,176,210 -5.1 1,229,848 -0.8 E-19 1,816,770 1,701,611 -6.3 1,763,147 -2.9 1,860,946 2.4 Streetlights 69,902 73,663 5.4 81,128 16.1 83,507 19.5 Standby 57,393 49,424 -13.9 57,442 0.1 59,655 3.9 Agriculture 864,360 992,048 14.8 1,055,745 22.1 1,001,247 15.8 E-20T 368,381 342,077 -7.1 369,881 0.3 388,002 5.3 E-20P 578,679 518,674 -10.2 575,081 -0.6 602,575 4.1 E-20S 231,437 211,138 -8.7 232,175 0.3 242,942 5.0 System 12,149,628 12,163,299 0.1 12,154,576 0.0 12,116,488 -0.3

Table 4B: Comparison of Allocation for DA/CCA Customers

CLECA PG&E ORA Class Present Rate

Revenues Total Revenue

Percent Change

Total Revenue

Percent Change

Total Revenue

Percent Change

Residential 85,604 84,921 -0.8 81,619 -4.7 79,783 -6.8 Small L&P 32,282 33,885 5.0 32,955 2.1 29,044 -10.0 Medium L&P 53,964 54,897 1.7 52,876 -2.0 57,575 6.7 E-19 223,887 216,846 -3.1 217,867 -2.7 239,873 7.1 Streetlights 888 972 9.5 1,091 22.9 1,134 27.7 Standby 1,708 1,507 -11.8 1,480 -13.4 1,492 -12.6 Agriculture 3,111 3,666 17.8 4,123 32.5 3,709 19.2 E-20T 53,801 54,034 0.4 52,684 -2.1 58,020 7.8 E-20P 121,760 113,307 -6.9 126,917 4.2 137,078 12.6 E-20S 46,114 41,904 -9.1 46,488 0.8 49,838 8.1 System 623,118 605,939 -2.8 618,100 -0.8 657,545 5.5

G. Revenue Allocation Capping and Flooring

Q132. What is capping?

A132. Capping is a process by which revenue increases to certain classes or rate

schedules are reduced below the results that come from a revenue allocation.

OFFICE OF RATEPAYER ADVOCATES CALIFORNIA PUBLIC UTILITIES COMMISSION

Testimony on Pacific Gas and Electric’s 2014 General Rate Case Phase II

TABLE OF CONTENTS

CHAPTER 1 ................................................................................................... 1-1

CHAPTER 2 ................................................................................................... 2-1

CHAPTER 3 ................................................................................................... 3-1

CHAPTER 4 ................................................................................................... 4-1

CHAPTER 5 ................................................................................................... 5-1

CHAPTER 6 ................................................................................................... 6-1

APPENDIX A – QUALIFICATION OF WITNESS

MEMORANDUM

1

List of DRA Witnesses and Respective Chapters

1

22

Costs are rooted in the actual situation23

III. PG&E’S MARGINAL GENERATION COST PROPOSALS A. Marginal Energy Costs

24

22 Id.23 The Theory of Public Utility Pricing and Its Application

24

25

B. Marginal Generation Capacity Costs

26

25

26

27

28

29

30

(continued from previous page)

28

29

30

Id, p.2-14, ll.7-17

IV. ORA’S MARGINAL GENERATION COST PROPOSALS A. ORA recommends adjusting PG&E’s MEC calculations

to consistently reflect PG&E’s standard TOU periods throughout the calculation of the MECs

31

B. ORA recommends that PG&E’s MGCC be based on a 2022 resource balance year.

new flexible capacity will be needed in 2018,

31

32

33

C. Track 2 of the 2012 LTPP examined system flexibility needs for 2022. The Commission concluded that system flexibility needs for 2022 may be low or non-existent and canceled Track 2.

Assigned Commissioner and Administrative Law Judge’s Ruling Regarding Track 2

and 4 Schedules

34

35

32

available at

33 available at LTPP Tracks 1 & 3

34 available at

35 R.12-03-014: LTPP Track II Workshop – SCE Operating Flexibility Modeling Results & Energy Division ELCC Modeling Efforts available at

D. ORA recommends that PG&E’s MGCC be based on a nine-year analysis period extended to include the 2022 resource balance year.

supra

E. ORA recommends that PG&E’s capital-related marginal costs be calculated based on PG&E’s pretax weighted capital cost, rather than the after-tax value proposed by PG&E.

supra

36

The TRC should be calculated utilizing a discount rate that reflects the utilities’ weighted average cost of capital, as adopted by the Commission. 37

38

36

37 R.01-08-028

38 I.05-06-041

39

V. CONCLUSION

39

CHAPTER 3 MARGINAL CUSTOMER ACCESS COSTS

VALERIE KAO

I. INTRODUCTION

ccosts that change

when the utility adds a customer.48

49

50

51

48

49

50

51

52

II. SUMMARY OF RECOMMENDATIONS

(continued from previous page)

52

53

53

III. DISCUSSION – HOOKUP EQUIPMENT COSTS AND ASSOCIATED OPERATIONS AND MAINTENANCE COSTS

Customer Class FERA Program Costs ($000)

V. MITIGATION

A. Capping Class Revenue Changes

Class

Present (May 2013)

Revenue ($000)

PG&E ORA


Average Percent Change


Average Percent Change

Application: 13-04-012 (U 39 M) Exhibit No.: (PG&E-4) Date: August 16, 2013 Witness: Various

PACIFIC GAS AND ELECTRIC COMPANY

2014 GENERAL RATE CASE PHASE II

UPDATE/ERRATA TESTIMONY

EXHIBIT (PG&E-4) VOLUME 1

REVENUE ALLOCATION AND RATE DESIGN

(PG&E-4)

-i-

PACIFIC GAS AND ELECTRIC COMPANY 2014 GENERAL RATE CASE PHASE II

EXHIBIT (PG&E-4) VOLUME 1 REVENUE ALLOCATION AND RATE DESIGN

TABLE OF CONTENTS

Chapter Title Witness

1 REVENUE ALLOCATION AND RATE DESIGN POLICY

Daniel R. Pease

2 REVENUE ALLOCATION PROPOSAL Patricia C. Gideon

3 RESIDENTIAL RATE DESIGN Emily Bartman Kamal Bilal Keith B. Coyne Dennis M. Keane Thomas L. Troup Phillip J. Quadrini

4 SMALL LIGHT AND POWER RATE DESIGN Phillip J. Quadrini

5 MEDIUM AND LARGE LIGHT AND POWER RATE DESIGN

Keith B. Coyne

6 STANDBY RATE DESIGN Daniel R. Pease

7 STREETLIGHTING RATE DESIGN Patrick Y. Lam

8 AGRICULTURAL RATE DESIGN Keith B. Coyne

(PG&E-4)


CHAPTER 1

REVENUE ALLOCATION AND RATE DESIGN POLICY

(PG&E-4)

1-i

PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 1

REVENUE ALLOCATION AND RATE DESIGN POLICY

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, Meaningful and Practical to Implement ............................. 1-4

C. Guidelines for Revenue Allocation and Rate Design ......................................... 1-5

1. Distribution Revenue Allocation and Rate Design ........................................ 1-5

a. Basic Service Fee ................................................................................... 1-6

b. Demand and Energy Charges ................................................................ 1-6

c. Time Differentiation of Demand and Energy Charges ............................ 1-6

2. PPP Revenue Allocation and Rate Design................................................... 1-7

3. Generation Revenue Allocation and Rate Design ........................................ 1-7

4. Total Residential Rates ................................................................................ 1-8

5. Revenue-Neutral Rate Design ..................................................................... 1-9

D. Revenue Allocation .......................................................................................... 1-10

E. Rate Changes Between GRCs ........................................................................ 1-13

F. Pending Issues ................................................................................................ 1-14

1. 2010 Rate Design Window: Peak Time Rebate ........................................ 1-15

2. 2012 RDW: Residential Rate Design ........................................................ 1-15

3. 2012 RDW: Dynamic and Time-Varying Pricing ........................................ 1-16

4. Distribution Bypass Deferral Rate Memo Account ..................................... 1-16

5. Baseline Balancing Account and the Common Area Balancing Account ... 1-16

6. Direct Access and Community Choice Aggregation Service Fees and Credits ........................................................................................................ 1-17

(PG&E-4) PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 1 REVENUE ALLOCATION AND RATE DESIGN POLICY

TABLE OF CONTENTS

(CONTINUED)

1-ii

G. Organization of the Exhibit .............................................................................. 1-17

H. Conclusion ....................................................................................................... 1-18

(PG&E-4)

1-10

D. Revenue Allocation 1

With rates by function designed based on full cost as described above, 2

proposed rates can be multiplied by bundled and Direct Access (DA) forecasted 3

billing determinants to estimate the total revenue and average rates for each 4

customer class taking bundled service and each customer class taking DA or 5

Community Choice Aggregation (CCA) service. As mentioned previously, for 6

purposes of this analysis, rates for distribution and generation are moved to full 7

cost based on the guidelines discussed in this chapter. As a result of these 8

changes, however, the rates for both the CARE surcharge component of PPP 9

and the CIA in the residential class are also revised. The full cost results reflect 10

only the changes in revenue allocation and rate design proposed in this 11

proceeding such that total revenue is equal to revenue at current rates. 12

Tables 1-1 and 1-2, provided below for bundled and DA/CCA customers, 13

respectively, summarize the change necessary to set each class’ respective 14

revenue responsibility at full cost. 15

TABLE 1-1 PACIFIC GAS AND ELECTRIC COMPANY

BUNDLED CLASS REVENUE SUMMARY BASED ON FULL COST

Line No. Class

Revenue at May 1, 2013

Rates ($000)

Revenue at Full Cost ($000)

Class Average Percent Change in

Revenues

1 Residential $5,309,098 $5,252,705 -1.1% 2 Small L&P 1,613,897 1,644,941 1.9% 3 Medium L&P 1,239,675 1,166,524 -5.9% 4 Schedule E-19 1,816,598 1,744,465 -4.0% 5 Streetlights 69,902 81,465 16.5% 6 Standby 57,393 57,108 -0.5% 7 Agriculture 864,360 1,050,270 21.5% 8 Schedule E-20 1,178,493 1,167,474 -0.9%

9 System $12,149,416 $12,164,951 0.1%

Company’s 2014 General Rate Case

COMPANY’S 2014 GENERAL RATE CASE

744(c)’s potential

PG&E’s

the report and discuss PG&E’s analysis and conclusions.

deadline for PG&E’s 2017 GRC Phase II application.

compliance item attached to PG&E’s next GRC Phase II application.

’s final

Application: 13-04-012 (U 39 M) Exhibit No.: (PG&E-5) Date: August 16, 2013 Witness: Various


2014 GENERAL RATE CASE PHASE II

UPDATE/ERRATA TESTIMONY

EXHIBIT (PG&E-5) VOLUME 1

MARGINAL COSTS

(PG&E-5)

-i-

PACIFIC GAS AND ELECTRIC COMPANY 2014 GENERAL RATE CASE PHASE II

EXHIBIT (PG&E-5) VOLUME 1 MARGINAL COSTS

TABLE OF CONTENTS

Chapter Title Witness

1 MARGINAL COST PROPOSALS Thomas L. Troup

2 MARGINAL GENERATION COSTS Yumi Oum

3 DEFERRABLE TRANSMISSION CAPACITY PROJECTS

Bangalore Vijayrahavan

4 MARGINAL TRANSMISSION CAPACITY COSTS Thomas L. Troup

5 DISTRIBUTION EXPANSION PLANNING PROCESS AND PROJECTED COSTS

Satvir Nagra

6 MARGINAL DISTRIBUTION CAPACITY COSTS Thomas L. Troup

7 MARGINAL CUSTOMER ACCESS COSTS Thomas L. Troup

(PG&E-5)


CHAPTER 1

MARGINAL COST PROPOSALS

(PG&E-5)

1-i


MARGINAL COST PROPOSALS

TABLE OF CONTENTS

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

B. Organization of Exhibit ...................................................................................... 1-2

C. The Economic Theory of Marginal Costs ........................................................... 1-4

D. The Commission’s Adopted Marginal Cost Methods ......................................... 1-5

E. PG&E’s Proposed Marginal Cost Approach ...................................................... 1-8

1. Marginal Generation Costs ......................................................................... 1-10

2. Marginal Transmission Capacity Costs ...................................................... 1-11

3. Marginal Distribution Capacity Costs ......................................................... 1-12

4. Marginal Customer Access Costs .............................................................. 1-13

F. Compliance With Data and Modeling Workshops Requirement in 2011 GRC Phase II Decision .................................................................................... 1-15

G. Conclusion ....................................................................................................... 1-17

(PG&E-5)

1-13

PG&E’s service territory has an extremely diverse geography and 1

customer density. PG&E has observed a wide variation in the marginal cost 2

of distribution capacity among the more than 240 distribution planning areas 3

(DPAs) that comprise its electric system, which have been aggregated into 4

18 divisions as PG&E has done since its 1993 GRC Phase II. As discussed 5

above, PG&E proposes MDCCs that utilize a location-specific, 6

timing-sensitive marginal cost methodology, as it has in every GRC since 7

Phase II of its 1993 GRC. 8

PG&E’s MDCCs consist of four marginal costs: (1) primary distribution 9

costs for large projects greater than 1 million dollars; (2) primary distribution 10

costs for projects less than 1 million dollars; (3) new business primary costs; 11

and (4) secondary costs. 12

PG&E proposes to use the same DTIM to calculate MDCCs of large 13

projects as it uses to estimate MTCC because of the lumpy nature of these 14

investments.16 DTIM-calculated MDCCs vary by area to reflect the fact that 15

investments during the planning horizon are needed at different times and in 16

different sizes for different areas depending on the installed capacity and 17

load growth unique to each area. The DTIM conforms to the Commission’s 18

guidance in Decision 92-12-057 and Commission-adopted marginal cost 19

principles, and is well suited for computing area-specific marginal costs. 20

Because other primary and secondary costs do not exhibit the same 21

lumpiness, PG&E’s estimates for these costs are based on three years of 22

recorded expenditures and two years of forecast expenditures. PG&E’s 23

estimates of MDCC costs are discussed in detail in Chapter 6, “Marginal 24

Distribution Capacity Costs.” 25

4. Marginal Customer Access Costs 26

PG&E’s proposed MCACs are based on the NCO method first adopted 27

for PG&E in its 1993 GRC (D.92-12-057). Unlike previous methods 28

(e.g., the Rental Method), the NCO method recognizes that new and 29

existing customers differ greatly in the marginal costs they cause and the 30

MCAC using this methodology reflects these differences. Since PG&E’s 31

16 While distribution investments are generally less lumpy than transmission investments,

geographic disaggregation increases the effect of lumpiness.

(PG&E-5)

1-14

1993 GRC, the Commission has repeatedly and appropriately rejected the 1

alternative Rental Method, which is based on the annualized cost of new 2

customer access equipment (final line transformers, service extensions, and 3

meters) applied to all customers17 on the basis that it overcharges 4

customers for the cost of the access equipment. 5

In addition to the one-time capital costs of new access equipment, 6

PG&E’s NCO-based MCACs also include the Operation and Maintenance 7

(O&M) costs for new connection access equipment captured as the present 8

value of the O&M costs over the lifetimes of the access equipment18 (since 9

the new connections impose the additional obligation, and its costs, to 10

maintain that access equipment), and the costs of RCS such as metering 11

(meter services and meter reading), billing, and other customer-related 12

service for all customers. PG&E has updated its RCS models in this GRC to 13

estimate the customer-class specific marginal cost for revenue cycle and 14

related services. For this GRC Phase II showing, PG&E has significantly 15

revised its RCS models to reflect the transition from analog to SmartMeter™ 16

metering technology and infrastructure and has disaggregated these meter-17

related costs to a greater degree than was possible with data available at 18

the time the original RCS models were developed. This update ensures that 19

the RCS models used in this GRC Phase II filing provide cost estimates that 20

are based on current meter-related RCS activities and costs, accounting for 21

all meter-related activities added or removed since the RCS models were 22

originally developed in 1999 and the associated SmartMeter™ cost savings. 23

With these updates, the RCS marginal costs provide more accurate 24

marginal cost estimates. 25

As explained in Chapter 7, “Marginal Customer Access Costs,” of this 26

exhibit, the structure of the RCS models allows PG&E to easily identify and 27

exclude fixed costs from the MCAC calculations, resulting in more accurate 28

marginal cost determinations. This is an improvement from the previously 29

17 The Rental Method applies these costs to all customers regardless of their need for new access

equipment. The Commission has rejected the Rental Method in numerous cases, including: D.92-12-057, D.95-12-053, D.96-04-050, D.97-03-017, D.97-04-082 and D.00-04-060.

18 This is done through the application of lifetime O&M adders that is described in Chapter 7, “Marginal Customer Access Costs,” in this exhibit.

(PG&E-5)


CHAPTER 7

MARGINAL CUSTOMER ACCESS COSTS

(PG&E-5)

7-i


MARGINAL CUSTOMER ACCESS COSTS

TABLE OF CONTENTS

A. Introduction ........................................................................................................ 7-1

B. Model Improvements ......................................................................................... 7-1

C. Background ....................................................................................................... 7-3

D. New Customer Only Methodology ..................................................................... 7-4

E. New Customer Connection Costs ...................................................................... 7-6

1. Rule 16 Service Extension Tariffs ................................................................ 7-7

2. New Customer Connection Costs by Customer Class ................................. 7-9

3. New Customer Connection Rate ................................................................ 7-10

4. Lifetime O&M for New Connections ........................................................... 7-11

F. Ongoing Marginal Customer Access Costs ..................................................... 7-14

1. Revenue Cycle Services Models ................................................................ 7-14

2. Metering, Billing, and Customer Service Marginal Costs ........................... 7-16

3. Other Account 903 ..................................................................................... 7-17

G. Marginal Customer Cost Categories and Results ............................................ 7-17

1. Marginal Customer Cost Categories .......................................................... 7-17

2. Marginal Customer Cost Results ................................................................ 7-19

H. Conclusion ....................................................................................................... 7-22

(PG&E-5)

7-3

C. Background 1

For most customer classes, the access costs for new connections comprise 2

the meter, service line, and, as applicable to the situation, final line transformer 3

and secondary conductor between the transformer and service line. 4

Additionally, all customers have ongoing costs, including meter maintenance, 5

meter reading, billing, and other customer service-related costs. During the first 6

decade of marginal cost-based electric ratemaking in California (in the 1980s), 7

Commission-adopted marginal cost methodologies generally did not distinguish 8

between costs attributable to new customers and costs attributable to existing 9

customers. In decisions up to and including Decision 89-12-057, the 10

Commission adopted the so called “rental method,” which attributes the full 11

annualized cost of a new transformer, service extension, and meter (sometimes 12

referred to as “TSM” costs)4 as a marginal cost to all customers, regardless of 13

their need for new access equipment. Because the rental method attributed the 14

annualized cost of new access (or “hookup”) equipment to all customers, it could 15

not distinguish between the very different costs caused by new customers 16

requiring new access equipment this year, and existing customers, whose 17

access equipment may not need replacing for many years into the future. 18

In its 1993 GRC, PG&E first proposed, and the CPUC adopted (in 19

D.92-12-057), a new method that separates MCAC into two explicit components: 20

(1) the one-time costs to connect a new customer which are attributed only to 21

new customers, and (2) the ongoing customer service costs that are incurred to 22

serve existing customers which are attributed to all customers.5 This separation 23

4 In Decision 89-12-057, the Commission recognized that the distribution system performs both a

capacity (demand-related) function and customer access function, where demand-related costs are assigned to marginal capacity costs, and access-related costs are assigned to MCAC. The distinction between these functions is not always clear. (D.89-12-057, mimeo, p. 202.) Primary distribution costs are treated as capacity costs (Ibid., mimeo, p. 203). Secondary distribution equipment includes secondary conductors, final line transformers, service drops and meters (Ibid., mimeo, p. 203). While this secondary system primarily provides customer access to the electric distribution system, the Commission accepted PG&E’s view that it also has a capacity component and assigns secondary investments for demand-related growth to marginal distribution capacity costs (Ibid., mimeo, p. 206). The remainder of the secondary equipment, along with associated ongoing costs such as meter services, meter reading, billing, and other customer services are assigned to MCAC.

5 See D.92-12-057, mimeo, p. 272. New and ongoing marginal customer costs were first used to calculate marginal customer cost revenues in the 1993 GRC Exhibit (PG&E-17), Chapter 2 workpapers, pages 203-214. Access equipment replacement costs were not included in the OTHC method when originally adopted in Decision 92-12-057.

A California Spring With Too Much Energy? Details on Page 4.

CEC Adopts Final Integrated Energy Policy Report Update . . . . . Jump to [5].

Potomac: Senate Confirms EPA Foe Pruitt to Head Agency . . . . . Jump to [6].

PG&E Safety Culture Investigation Report Expected Soon . . . . . Jump to [7].

Bottom Lines: Planning for Wildfires and Mega-Storms . . . . . . . . . Jump to [8].

The Race Is On to Repair Oroville Spillways . . . . . . . . . . . . . . Jump to [11.1].

FEMA Gears Up for Possible Spillway Failure . . . . . . . . . . . . . . . . . Jump to [11.2].

FERC Inspector Noted Seepage at Spillway in 2013 . . . . . . . . . Jump to [11.3].

Legal and Regulatory Issues Still Dog PG&E . . . . . . . . . . . . . . Jump to [13.1].

NMPRC Cool Toward Non-Utility Community Solar Bill . . . . Jump to [14.1].

ACC’s Burns Floats Rule on Transparency, Campaign Finance . . . . . . Jump to [14.2].

[1] Oroville Emergency Highlights Dam Safety, Climate Change Concerns

[2] Navajo Nation Considers Owning Coal Plant in Crisis

[3] Cogentrix Urges CAISO to Move Fast on Flexible Capacity

[4] Big Rate Hikes Boost PG&E Earnings

Photo: DWR

Copyright © 2017, Energy NewsData Corporation. Unauthorized reproduction is strictly prohibited.

Page 13

[13.1] With High-Profile Cases Closed, Legal and Regulatory Issues Still Dog PG&E

The utility sees more widespread

adoption of EVs as an opportunity.

DESCRIPTION OF PG&E’

BY THE COMMISSION’S

PG&E’s presently effective

PG&E’s proposed changes in electric rates

For more than thirty years, Diablo Canyon Power Plant (“DCPP” or “Diablo Canyon”)

gas (“GHG”)

the Nuclear Regulatory Commission (“NRC”) for

With this timing in mind, Pacific Gas and Electric Company (“ ”)

ectrical Workers (“IBEW”) Local 1245,

(“CEEIC”) has indicated that i

PG&E’s

Portfolio Standard (“RPS”)

PG&E’s employees and the community

to keep Diablo Canyon’

Electric Company’s 2014 General Rate Case

FILED12-02-1404:59 PM

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