MARGINAL COST AND REVENUE ALLOCATION

PREPARED REBUTTAL TESTIMONY OF

WILLIAM PEREA MARCUS AND ROBERT FINKELSTEIN

ON MARGINAL COST AND REVENUE ALLOCATION

PUBLIC VERSION (REDACTED)

Submitted on Behalf of

THE UTILITY REFORM NETWORK

785 Market Street, Suite 1400 San Francisco, CA 94103

Telephone: (415) 929-8876 Facsimile: (415) 929-1132

February 26, 2021

CPUC Docket: A.19-11-019 Witnesses: William Marcus and Robert Finkelstein Exhibit: TURN-2

Prepared Testimony of William Perea Marcus and Robert Finkelstein Page i on behalf of TURN in App. 19-11-019 (PG&E GRC Phase 2)

Table of Contents

I. Introduction ....................................................................................................................... 1

II. Revenue Allocation – Wildfire Mitigation, CEMA and HSM Costs ......................... 1

A. Summary of recommendations ...................................................................................... 1

B. Wildfire Mitigation Costs ............................................................................................... 4

1. Wildfire Risk Mitigation Costs Should Be Allocated As A Public Policy Program, Rather Than As A Part of PG&E’s Cost of Providing Distribution Service 4

2. Wildfire Risk Mitigation 2022 revenue requirement calculations ........................ 8

3. Wildfire Mitigation Cost Allocation Recommendation ....................................... 11

C. CEMA - Recorded Costs ............................................................................................... 12

D. HSM Costs Have Virtually Nothing To Do With Distribution Service, Equipment, or Costs. ................................................................................................................................... 14

III. Marginal Generation Capacity Costs ........................................................................... 15

A. Issues that are now Largely Uncontested ................................................................... 17

B. Return on Common Equity .......................................................................................... 18

C. Response to FEA/EPUC ............................................................................................... 18

D. Response to CLECA ....................................................................................................... 20

1. Change MGCC escalation for 2028 and beyond .................................................... 21

2. Six Hour Battery Requirement ................................................................................. 21

3. RECC with Deflation instead of Inflation ............................................................... 23

4. Battery Capital Costs ................................................................................................. 24

5. Minimum Profit Levels for Batteries used in Arbitrage ....................................... 25

6. A point of comparison: the Moss Landing Battery Contract ............................... 26

7. Summary ..................................................................................................................... 27

IV. Marginal Energy Costs ................................................................................................... 28

Prepared Testimony of William Perea Marcus and Robert Finkelstein Page ii on behalf of TURN in App. 19-11-019 (PG&E GRC Phase 2)

List of Tables

Table 1: Estimated Wildfire Risk Mitigation Revenue Requirements .............................................. 10

Table 2: Comparison of Marginal Generation Capacity Cost Estimates .......................................... 16

Table 3: Lazard Study Cost of 100 MW, 4 Hour Battery ($/kW-year) ............................................. 25

Table 4: TURN’s Marginal Generation Capacity Cost Revised for Rebuttal Case ......................... 27

Table 5: PG&E and TURN Marginal Energy Costs by Time Period Revised for Rebuttal Case .. 28

Prepared Testimony of William Perea Marcus and Robert Finkelstein (PUBLIC - REDACTED) Page 1 on behalf of TURN in App. 19-11-019 (PG&E GRC Phase 2)

I. Introduction

This rebuttal testimony is sponsored by William Perea Marcus and Robert Finkelstein

on behalf of The Utility Reform Network (TURN). Mr. Marcus and Mr. Finkelstein are

co-sponsoring Section II (Revenue Allocation) and Mr. Marcus is the sole sponsor of

Sections III (Marginal Generation Capacity Costs) and IV (Marginal Energy Costs). Mr.

Marcus’ qualifications are contained in Attachment 1 of TURN’s direct testimony (Ex.

TURN-1). Mr. Finkelstein’s qualifications are contained in Attachment 1 of this rebuttal

testimony.

TURN’s rebuttal testimony addresses recommendations made by parties in direct

testimony. In Section II, TURN endorses allocating Wildfire Mitigation, Catastrophic

Event Memorandum Account (CEMA) and Hazardous Substance Mechanism (HSM)

costs using an equal cents per kilowatt-hour approach and collected in the Public

Purpose Program (PPP) rate component. In Section III, TURN responds to

recommendations relating to Marginal Generation Capacity Costs. In Section IV, TURN

agrees with the proposal to include an adder for short-run renewable costs to marginal

energy costs.

II. Revenue Allocation – Wildfire Mitigation, CEMA and HSM Costs

A. Summary of recommendations

TURN’s opening testimony expressed support for CalPA’s proposal to move $294

million recorded in the Catastrophic Event Memorandum Account (CEMA) and $29.8

million of Hazardous Substance Mechanism (HSM) costs from the distribution revenue

requirement to public purpose program charges, and to allocate them by equal cents

per kWh rather than using a distribution allocator.1 The opening testimony of

California Farm Bureau Federation (CFBF) similarly proposed allocating wildfire

1 TURN Direct Testimony (Ex. TURN-1), p. 33.


mitigation costs on an equal cents per kWh basis rather than via a distribution allocator.

CFBF identified $224.4 million of costs that should be subject to this treatment by

relying on PG&E’s calculation of wildfire mitigation costs included in its May 1, 2020

revenue requirement.2 On the other hand, the opening testimony of CLECA opposed

CalPA’s proposal, arguing in favor of a distribution allocator for CEMA and HSM

costs.3

After reviewing the opening testimony of the other intervenors and upon further

consideration and analysis of these issues, TURN recommends that the Commission

adopt the equal cents per kWh allocation for Wildfire Mitigation costs, consistent with

the general principle underlying CFBF’s recommendation. However, that allocation

must apply to the full range of Wildfire Mitigation costs that are likely to be included in

authorized revenue requirements during the period when this Phase 2 decision is in

effect. TURN’s current estimate is that PG&E’s Wildfire Mitigation costs in 2022 will

amount to approximately $1.4 billion of revenue requirement in 2022. The revenue

requirement amounts in 2023 and thereafter are harder to estimate at this juncture but

will certainly be far in excess of the $524 million cumulative adjustment under the

proposals of CalPA and CFBF.4

Wildfire Mitigation costs encompass the costs of increments of work or expense, often

associated with entirely new activities, that were not part of providing utility service

before the advent of the “new abnormal” of wildfire risk associated with Climate

Change.5 The broad category of Wildfire Mitigation costs, covering activities such as

“enhanced vegetation management” and “system hardening,” should be treated as the

2 CFBF Opening Testimony, p. 9, and CFBF Attachments, Response to DR 3, Question 6. 3 CLECA Opening Testimony, pp. 3 and 55. 4 TURN continues to support an equal cents per kWh allocation for Hazardous Substance Mechanism (HSM) costs and CEMA-recorded costs incurred in response to catastrophic events other than wildfires (i.e. storms and earthquakes). 5 PG&E Testimony in Phase 1 of its test year 2020 GRC, PG&E-04, p. 2A-1 [“The devastating wildfires which occurred in 2017 and 2018 throughout California leave no doubt that we have entered a ‘new abnormal’ of wildfire risk.”] – See Attachment 2.


equivalent of a “public purpose program” undertaken to respond to the increased

wildfire risk that is another manifestation of Climate Change in California. But for

Climate Change and the increased wildfire risk it has created, there would have been no

need for SB 901 or AB 1054, or for the very ambitious and very expensive utility

programs undertaken to comply with that legislation. Whether the Commission

removes these costs from the distribution function and transfers them to the Public

Purpose Program (PPP), as CalPA has proposed, or leaves them as a part of the

distribution function but allocates them on a different basis than the distribution

allocator, as CFBF seems to propose, the costs should be allocated in a manner

consistent with the public purpose nature of those costs, preferably on an equal cents

per kWh basis.

Similar logic should lead the Commission to reject CLECA’s position calling for costs

recorded in the Catastrophic Event Memorandum Account (CEMA) to be allocated on a

functional basis. The costs of responding to catastrophic events (not only wildfires but

severe storms as well) are caused by the events themselves, not by the size of a

particular utility customer or the demand that customer places on PG&E’s system.

Furthermore, the growing number and severity of such events indicates the linkage

with Climate Change and provides further reason to treat CEMA costs as a Public

Policy Program rather than an element of providing distribution service.

Finally, allocating Hazardous Substance Mechanism (HSM) costs to the distribution or

generation function, as suggested by CLECA, would only make sense if current

customers were taking service from Manufactured Gas Plants or if PG&E’s current

operations contributed to a declared Superfund site. The HSM costs are a vestige of

PG&E’s historical operations and represent a change in public policy calling for current

clean-up efforts for toxic waste that was produced many decades ago but was not

disposed of properly at the time.


B. Wildfire Mitigation Costs

1. Wildfire Risk Mitigation Costs Should Be Allocated As A Public Policy Program, Rather Than As A Part of PG&E’s Cost of Providing Distribution Service

The opening testimony of CLECA opposes CalPA’s proposal to use an equal cents per

kWh allocator for costs recorded in PG&E’s CEMA, a subset of which represent costs

incurred in responding to catastrophic wildfires. CLECA asserts that such an approach

would “deviate sharply from a cost-of-service basis.”6 CLECA instead supports

PG&E’s proposed allocation of such costs using distribution cost allocators to the extent

the costs are “distribution capital expenditures and [O&M] costs.”7 By CLECA’s logic,

any spending on equipment or activities of a type that was previously recovered using

a distribution allocator should be subject to that same allocator going forward. Under

that logic, Wildfire Mitigation costs, the bulk of which involves spending on

distribution facilities or new Vegetation Management programs, would be allocated

based on a distribution allocator.

TURN believes CLECA’s approach does not adequately consider a critical distinction

that applies to both recent CEMA costs and Wildfire Mitigation costs. The costs at issue

are incurred as part of the broad response to Climate Change and its wildfire-related

impacts (storms with greater destructive capacity and wildfires in greater numbers and

of greater size and destruction). In this way, the CEMA and Wildfire Mitigation costs

should be characterized as programs responding to wildfire risks rather than costs

related to connecting, or serving, any individual customer or group of customers. The

appropriate cost allocation should reflect this distinction.

California policymakers have long recognized that one of the most dangerous aspects of

Climate Change is the increased risk of catastrophic wildfires. In 2014, the Commission

issued Resolution ESRB-4 which acknowledged the link between greenhouse gas

6 CLECA Opening Testimony, p. 3. 7 CLECA Opening Testimony, p. 55.


emissions, climate change, and increased wildfire risk. The Commission explained that

the increased wildfire risk (at its 2014 level) is a product of climate change and, in

particular, the then-ongoing drought.8 It also recognized that wildfires create a vicious

cycle with regard to climate change, in that they destroy forests that are critical to

reducing the amount of greenhouse gases in the atmosphere.9 It found that the drought

and recent wildfires “occur as examples establishing the severity of the impacts of

Climate Change on Californians.”10 As a result, the Commission directed PG&E, along

with the other IOUs, to increase vegetation inspections and remove hazardous, dead

and sick trees near their electric power lines and poles.11

In AB 1054 (2019), the California Legislature included several findings and declarations

addressing the broad threats posed by catastrophic wildfires to both communities and

properties throughout the state and the electrical utilities’ costs of financing that could

cause all customers to face potentially higher costs due to wildfire-related financial

liability. Partly on this basis, the Legislature found and declared, “The state’s electrical

corporations must invest in hardening of the state’s electrical infrastructure and

vegetation management to reduce the risk of catastrophic wildfire.”12

PG&E recently filed A.20-09-019 seeking rate recovery of the revenue requirement

associated with costs recorded through the end of 2019 in various memorandum

accounts established for tracking Wildfire Mitigation costs. The supporting testimony

includes a discussion of the background of the programs that had resulted in the

recorded costs and begins with a section entitled “Climate Change and Increased

8 Resolution ESRB-4, p. 6. 9 Resolution ESRB-4, pp. 8-9 and Finding of Fact 11. 10 Resolution ESRB-4, Finding of Fact 12. 11 PG&E has recorded and now seeks rate recovery of $562 million for the incremental costs of the Tree Mortality & Fire Risk Reduction efforts undertaken in response to Resolution ESRB-4. The request is pending in A.18-03-015. 12 AB 1054, Sections 1(a)(1), 1(a)(2), and 2(b).


Catastrophic Wildfires.” The section provides a summary of the factors and conditions

underlying the need for the Wildfire Mitigation spending included in the application:

California has experienced dramatic environmental changes in recent years, including extremely strong wind events, unprecedented tree mortality, record rainfall, heat waves, and drought. As a result, the frequency and scope of wildfires in California has also increased substantially. In 2017 alone, California experienced five of the 20 most destructive fires in its history up to that point in time. In November 2018, California experienced two more devastating fires—the Camp Fire in Northern California and the Woolsey Fire in Southern California. The Camp Fire is now considered the most destructive wildfire in California history, with over 80 fatalities and extensive property destruction. A number of climate-related factors have contributed to the increasing risk of wildfires. For example, bark beetles and drought have contributed to record numbers of dead trees that fuel and amplify wildfires. According to the United States Forest Service (USFS), approximately 163 million trees have died in California since 2010. Moreover, as air temperatures rise, forests and land are drying out, increasing fire risks and creating weather conditions that readily facilitate the rapid expansion of fires.13

Later in its testimony, PG&E explains how its prior GRC revenue requirements had

contemplated “routine or baseline levels of emergency response activity, vegetation

management, electric asset inspection work, and electric asset maintenance and

replacements.” But in recent years, the utility has incurred incremental costs above and

beyond these “routine or baseline” levels that include its “catastrophic event response

and the significant wildfire mitigation work [PG&E] has undertaken to address

heightened wildfire risks and comply with rule and policy changes in furtherance of

this goal.”14 PG&E is describing efforts undertaken to mitigate wildfire risks consistent

with California’s emerging public policy. The costs of those efforts should be allocated

in a manner consistent with the nature of those costs.

13 A.19-09-019 (PG&E 2020 Wildfire Mitigation and Catastrophic Events), pp. 2-5 to 2-6 [footnotes omitted]. See Attachment 3. 14 A.19-09-019 (PG&E 2020 Wildfire Mitigation and Catastrophic Events), p. 8-1. See Attachment 3.


PG&E’s spending on Wildfire Mitigation programs and activities in 2022 will largely be

covered by the outcomes adopted in its test year 2020 GRC which will be in effect

through 2022. PG&E’s GRC testimony included a chapter on “Wildfire Risk Policy and

Overview.” In discussing the significant increase in wildfire risks in California

generally and PG&E’s service territory particularly, the utility stated that the factors

contributing to the increasing risk of wildfires are “primarily climate-related.” It cited

impact of bark beetles and drought as causes for the record number of dead trees that

fuel and amplify wildfires, as well as the general impact of rising temperatures

resulting in increasing fire risks and creating weather conditions that facilitate the rapid

expansion of fires.15 PG&E developed a Community Wildfire Safety Program (CWSP)

and proposed to spend approximately $5 billion between 2018 and 2022.16 A substantial

amount of the funding was slated for Enhanced Vegetation Management (Enhanced

VM), which PG&E distinguished from its previously existing Vegetation Management

programs that “already comply with vegetation clearance regulations and

environmental regulations.” The Enhanced VM programs in the GRC were developed

specifically to enable additional efforts in areas designated as subject to a high wildfire

threat.17 Similarly, the system hardening programs target reducing the risk of ignition

from utility equipment located in in high wildfire risk areas.18

In sum, the Commission should find that PG&E’s spending on Wildfire Mitigation is

the result of a profound and ongoing shift in California public policy to better address

the newly emergent wildfire risks. TURN does not dispute that the spending is largely

on distribution equipment or activities typically associated with distribution service.

However, allocating the costs as if they were just another element of providing

distribution service would ignore the fundamental purpose of addressing wildfire risk

15 A.18-12-009 (PG&E test year 2020 GRC), Ex. PG&E-04, Vol.1, pp. 2A-2 to 2A-4. See Attachment 2. 16 Id., p. 2A-23. 17 Id., p. 2A-26 18 Id., pp. 2A-27 to 2A-28.


in PG&E’s service territory and the broader public purpose of Wildfire Mitigation

efforts.

2. Wildfire Risk Mitigation 2022 revenue requirement calculations

The Commission should reasonably expect that PG&E’s Wildfire Mitigation revenue

requirement will total approximately $1.4 billion in 2022 alone and will continue to be

very substantial in the years to follow.

CFBF’s testimony identifies $224.414 million of wildfire mitigation costs and

recommends that amount should be allocated on an equal cents per kWh basis rather

than based on the distribution allocator. The $224 million figure was provided by

PG&E in response to a CFBF data request asking for the amount of wildfire mitigation

costs included in the revenue requirements that serve as the basis for PG&E’s Phase 2

proposals. PG&E explained that its proposals in this proceeding are based on the

revenue requirement in effect on May 1, 2020, and identified $224.4 million as the

amount it had “mapped” to wildfire risks.19 CFBF noted that the wildfire mitigation

costs are likely to increase significantly citing the “Enhanced Vegetation Management”

amounts in PG&E’s 2020 Wildfire Mitigation Plan ($443 million for 2019, and $495

million for 2020).20

TURN agrees with CFBF that all Wildfire Mitigation costs should be allocated on an

equal cents per kWh basis rather than using a distribution allocator. However, the

$224.4 million figure is vastly understated. Rather than calculating the amount based

on a “mapping” of the revenue requirement authorized as of May 1, 2020 (when few of

the Wildfire Mitigation programs had yet been included in rates), the amount should

reflect the anticipated Wildfire Mitigation revenue requirement in 2022, when the

revenue allocation methods adopted in this proceeding are slated to go into effect.

19 CFBF Opening Testimony, p. 9, and CFBF Attachments, Response to DR 3, Question 6. 20 CFBF Opening Testimony, p. 9.


There are two distinct time periods associated with the amounts likely to be recovered

in authorized 2022 revenue requirements. The first covers PG&E’s recorded spending

through the end of 2019, all of which is prior to the effective date of its test year 2020

GRC. PG&E’s Wildfire Mitigation spending through 2019 was recorded in several

memorandum accounts and each is the subject of reasonableness reviews slated to

conclude in late 2021. To the extent found reasonable, these memorandum account

balances are likely to be recovered in rates during 2022. The second time period covers

PG&E’s authorized spending during 2022 addressed in its test year 2020 GRC.

For purposes of estimating the total 2022 revenue requirement for programs and

activities of Wildfire Mitigation, TURN uses two categories – Enhanced VM, and Non-

VM Wildfire Mitigation. The Enhanced VM category covers the activities and

associated costs that PG&E has distinguished from its “routine” VM. The Non-VM

Wildfire Mitigation category covers system hardening, and everything else that is not

related to vegetation management. These estimates are shown in Table 1.


Table 1: EST. WILDFIRE RISK MITIGATION REVENUE REQUIREMENTS21

Category Amounts proposed for inclusion in 2022 Rev Req (millions)

Notes

Enhanced VM – Costs recorded through 2019

$124 Fire Hazard Prevention Memo Acct (FHPMA).22 $191 Wildfire Mitigation Plan Memo Acct (WMPMA).23 $208 CEMA-recorded Enhanced VM.24

Enhanced VM – 2022 $460 Authorized in 2020 GRC decision (D.20-12-005).25 Non-EVM Wildfire Mitigation – Costs recorded through 2019

$123 Fire Risk Mitigation Memorandum Account (FRPMA)/Wildfire Mitigation Plan Memo Acct (WMPMA).26

Non-EVM Wildfire Mitigation – 2022

$268 The Commission approved Community Wildfire Safety Program (CWSP).27

Total $1,374 million

21 The workpaper supporting these calculations is in Attachment 6 to this testimony. 22 $293 mm total revenue requirement for EVM recorded in FHPMA per PG&E (A.20-09-019 Testimony, Table 10-5 -- See Attachment 3.). D.20-10-026 (p. 31) authorized interim rate recovery of 55% of total over 17-month period 1/21 through 5/22. PG&E seeks recovery of the remaining 45% of total over the 12-month period 6/22 through 5/23 (Id., p. 10-10). Amount for 2022 recovery calculated as 5/17 of interim recovery amount (for 1/22 through 5/22), and 7/12 of remaining 45% (for 6/22 through 12/22). 23 $449.5 mm total expense recorded for Enhanced VM in 2019 (A.20-09-019 Testimony, Table 2-22 on p. 2-64 See Attachment 3.). D.20-10-026 (p. 31) authorized interim rate recovery of 55% of total over 17-month period 1/21 through 5/22. PG&E seeks recovery of remaining 45% of total over 12-month period 6/22 through 5/23 (Attachment 3, p. 10-10). Amount for 2022 recovery calculated as 5/17 of interim recovery amount (for 1/22 through 5/22), and 7/12 of remaining 45% (for 6/22 through 12/22). 24 $562 mm total revenue requirement for costs recorded in 2016-2019, per A.18-03-015 (Third Amended Application, Table 1-1. See Attachment 4. D.19-04-039 (p. 7) authorized interim rate recovery of 63%. Remaining 37% of $562 mm is $208 mm. 25 The 2020 GRC decision authorized $663 mm for 2022 on a combined basis for “routine” and “enhanced” VM. PG&E’s forecast for 2020 was $229 mm for “routine” VM (37% of total), and $378 mm for “enhanced” VM (63% of total). D.20-12-005, p. 74. Adopted settlement provided for $548 mm combined in 2020, increasing to $603 mm in 2021 and $663 mm in 2022. Estimate here is 63% of the 2020 authorized amount ($345 mm), plus the additional increment for 2022 ($663-$548 = $115 mm), consistent with PG&E’s GRC testimony seeking incremental funding in 2021 and 2022 for “enhanced” VM only. 26 $740 mm total revenue requirement (Table 10-5 from PG&E testimony in A.20-09-019), reduced by $449.5 mm that was Enhanced VM expense (Table 2-22) yields $290.5 million of non-VM revenue requirement. See Attachment 3. D.20-10-026 authorized interim rate recovery of 55% of total over 17-month period 1/21 through 5/22. PG&E seeks recovery of remaining 45% of total over 12-month period 6/22 through 5/23. Amount for 2022 recovery calculated as 5/17 of interim recovery amount (for 1/22 through 5/22), and 7/12 of remaining 45% (for 6/22 through 12/22). 27 CWSP amounts grow from 2020 to 2022 (O&M grows from $53 mm to $57 mm; capital grows from $603 mm to $1,151 mm). The 2022 revenue requirement estimate is calculated as the full amount of forecasted O&M for 2022 ($57 mm), plus the capital revenue requirement for 2022 (using 10% as the revenue requirement associated with depreciation, taxes and AB 1054-reduced return on the 2020-22 capital spending, and the mid-year convention for 2022 spending).


3. Wildfire Mitigation Cost Allocation Recommendation

TURN recommends that the Commission adopt the CFBF recommendation to allocate

Wildfire Mitigation costs on an equal cents per kWh basis subject to two modifications.

First, and most importantly, it should apply the equal cents allocation to the actual 2022

amounts since the total is likely to be closer to $1.4 billion in the 2022 revenue

requirement than the $224.4 million figure PG&E calculated for CFBF. This can be

achieved by applying the equal cents per kWh allocator to the cumulative 2022 revenue

requirement associated with amounts recorded in the various memorandum accounts

and balancing accounts created for recording Wildfire Mitigation costs.28 For revenue

requirements associated with costs through the end of 2019, the memorandum accounts

should include:

• Fire Hazard Prevention Memorandum Account (FHPMA)

• Fire Risk Mitigation Memorandum Account (FRMMA)/Wildfire Mitigation Plan

Memorandum Account (WMPMA)

• Catastrophic Event Memorandum Account (CEMA) (for Tree Mortality & Fire

Risk Reduction activities)

For Wildfire Mitigation costs incurred beginning in 2020, the 2022 revenue requirement

should also include:

• Vegetation Management Balancing Account (VMBA) (for Enhanced VM

activities)

• Wildfire Mitigation Balancing Account (WMBA) (for Community Wildfire Safety

Program and other expenditures)

Second, TURN believes the Wildfire Mitigation costs should be recovered via the Public

Purpose Program (PPP) rate component. CFBF’s testimony does not directly address

the question of whether the Wildfire Mitigation costs would be treated as a separate

28 Application of this allocation to costs in 2023 and thereafter may be achieved in the Annual Electric True-up (AET) advice letter process.


category of distribution costs or recovered as part of PPP.29 Including these costs in the

PPP is more appropriate given their linkage to California’s efforts to combat the effects

of Climate Change. Furthermore, it would be consistent with PG&E’s proposed

treatment of the Self-Generation Incentive Program (SGIP) and California Solar

Initiative (CSI) Program costs. The utility seeks to move both sets of costs from

distribution to PPP with SGIP costs allocated in a unique manner and CSI costs

allocated “based on the standard EPT allocation for non-CARE PPP revenue.”30

Furthermore, the collection of these costs in the PPP recognizes their nonbypassable

designation and would ensure collection from all customers including those taking

service on Net Energy Metering tariffs and those relying on other forms of self-

generation.

C. CEMA - Recorded Costs

CLECA’s testimony opposes the CalPA proposal to move CEMA costs from

distribution to the PPP based on the argument that, to the extent a catastrophic event

requires PG&E to incur costs to repair or replace distribution equipment, the nature of

those costs is distribution.31 CLECA quotes passages from PG&E’s testimony in a

recent CEMA application (A.18-03-015) to support the point that the severe weather

events such as storms and wildfires that qualify for CEMA cost recovery tend to

damage distribution equipment. In TURN’s view, the more important fact is that the

events resulting in costs recorded to CEMA are becoming more extreme and severe.

PG&E’s testimony in A.18-03-015 states, “In recent years, the weather impacting the

29 CFBF Testimony, pp. 10-11. 30 Ex. PG&E-3, p. 1-11. PG&E proposes two allocations for Public Purpose Programs; either an equal cents per kWh basis (as PG&E proposes for the cost of the CARE program), or an Equal Percent of Total Revenue (EPT) basis for other PPPs. Ex. PG&E-1, p. 1-9. TURN recommends the equal cents per kWh basis as the most equitable allocation of Wildfire Mitigation costs. However, if necessary, the Commission could apply the EPT allocator and it would still be a far more appropriate treatment than applying a distribution allocator. 31 CLECA Testimony, pp. 55-56.


PG&E service territory has been record-setting and extreme.”32 PG&E goes on to cite

examples of extreme and prolonged drought, followed by periods of heavy rain, then

record high temperatures causing numerous fire emergencies.33 The CEMA costs

recorded in recent years continues this pattern – the total revenue requirement for 2016

events was approximately $20 million; for 2017, 2018 and 2019 events, the total revenue

requirement jumped to approximately $125 million, $131 million, and $145 million,

respectively.34 In each of those years, a single CEMA event resulted in revenue

requirement amounts of approximately $100 million or more.35

CLECA’s arguments for continuing to allocate CEMA costs based on a distribution

allocator are unpersuasive. In recent years, the substantial increases in these costs are

more closely tied to the real-world impacts of Climate Change and CalPA’s proposal to

move them to Public Purpose Program costs is consistent with this development.

CalPA proposed moving $294.3 million from distribution to PPP as the necessary

adjustment to make the May 1, 2020 revenue requirement reflect its proposal. By

coincidence the proposed adjustment is approximately the same as would be necessary

to implement the change in the 2022 revenue requirement. In reviewing CEMA-related

materials to identify the portion that is associated with Enhanced VM (discussed in a

preceding section), TURN determined that the $294.3 million figure from PG&E’s

Annual Electric True-Up (AET) Advice Letter for May 1, 2020 revenue requirements

represents the amount authorized for interim rate recovery in the underlying CEMA

proceeding (A.18-03-015; D.19-04-039). Furthermore, it includes costs of an Enhanced

VM program (the Tree Mortality & Fire Risk Reduction program undertaken pursuant

to Res. ESRB-4), in addition to more typical CEMA costs. For the 2022 revenue

32 A.18-03-015, PG&E Testimony, p. 1-8. See Attachment 5. 33 A.18-03-015, PG&E Testimony, pp. 1-8 to 1-10. 34 See Attachment 7 for the underlying calculations from various PG&E CEMA requests covering this period. 35 The 2017 Tubbs Fire ($105.77 million); the 2018 Carr Fire ($98.9 million); and the 2019 January and February Severe Storm ($131.6 million).


requirement, TURN has calculated the portion of the remaining revenue requirement

from A.18-03-015 that is not for the Enhanced VM program, as well as the CEMA costs

PG&E has included in A.20-09-019. 36 The resulting total is $309 million, a figure that

serves as a reasonable estimate of the amount the Commission should expect to need to

remove from distribution and include in PPP for the 2022 revenue requirement in order

to implement CalPA’s recommendation.

D. HSM Costs Have Virtually Nothing To Do With Distribution Service,

Equipment, or Costs.

CLECA opposes CalPA’s proposal to move Hazardous Substance Mechanism (HSM)

costs out of distribution costs and into PPP charges and to allocate them on an equal

cents per kWh basis. CLECA asserts that the costs should be “functionalized on the

same basis as the plant to which the hazardous material is associated.” In support of

this assertion, CLECA goes on to state:

This is appropriate because the hazardous waste was generated by the generation or distribution plant while it was providing the generation or distribution services. It is appropriate that the users of that service should pay for the hazardous waste costs. The generation or distribution cost in the HSM should be allocated consistently with the overall generation or distribution revenue requirement.37

CLECA’s logic lacks factual support in several ways. First, it fails to acknowledge that,

for the hazardous waste costs included in the HSM revenue requirement, whatever

“generation or distribution services” might have been associated with the production of

that waste were provided to customers decades ago. And while it may be appropriate

that the users of the particular service that produced the hazardous waste pay for the

36 The non-Enhanced VM spending ($157 mm, from A.18-03-015 (Third Amended Application, Table 1-1), adjusted to $58 mm to reflect 63% interim rate recovery in D.19-04-039. See Attachment 4. From A.20-09-019, the full $251 mm revenue requirement for CEMA portion of request, as D.20-10-026 denied interim rate recovery for CEMA amounts in that application. See Attachment 3, Table 10-5. 37 CLECA Testimony, p. 57.


associated costs of dealing with that waste, it is unlikely that many of those customers

are still alive, much less taking bundled service from PG&E. Finally, it describes an

allocation of generation costs to the generation revenue requirement when, in fact, no

such allocation takes place – PG&E allocates the entire electric share to the distribution

revenue requirement, as CalPA’s testimony made clear.38

The costs recorded in the HSM are not costs associated with providing utility service to

current utility customers. Rather, they are costs PG&E incurs because public policy

changed. When the hazardous substances were produced, waste disposal requirements

were very different than they are today. Since then, there has been a broad recognition

that toxic materials need to be cleaned up or otherwise mitigated to promote public

health and safety. The costs today of remediating hazardous substances produced in

the utility’s historical operations, often by plants and facilities that no longer exist, are

about as relevant current utility service as is whale oil or the horse-and-buggy.

The Commission should adopt CalPA’s proposal to collect HSM costs as part of Public

Purpose Programs and assign the costs to customer classes using the equal cents per

kWh allocator.

III. Marginal Generation Capacity Costs

Table 2 below shows the marginal generation capacity costs provided by PG&E

(original and errata), TURN (original and in rebuttal), CLECA, and EPUC and FEA,

who both recommend the same number with the same rationale.

38 CalPA Testimony, p. 6-13, citing PG&E’s response to the Master Data Request.


Table 2: Comparison of Marginal Generation Capacity Cost Estimates

PG&E July PG&E January TURN TURN rebuttal CLECA FEA/EPUCcost (generation voltage

before 15% reserve margin

adder) 102.66$ $56.08 to $59.48 49.72$ 57.45$ 263.44$ $197.72 to $385

cost $1205 in 2021, declining $1205 in 2021, declining $1205 in 2021, declining $1205 in 2021, declining

higher capital costs ($1371 vs. $1205 in 2021) $1205 in 2021, declining

ROE/RECC high ROE PG&E current ROE PG&E current ROE PG&E current ROEPG&E's current ROE, revise RECC for deflation in battery costs high ROE

average of years of MGCC six-year average

six year average (fixed O&M of

combined cycle more expensive

than battery in 2026)



than battery in 2025-26



than battery in 2026 six-year average single-year 2022

energy savings include energy savings

new extrapolation of energy savings 2028-2043 (both PG&E and CLECA methods shown) PG&E July assumptions

new extrapolation of energy savings 2028-2043 (PG&E method)

reduce energy savings for new extrapolation of energy savings 2028-2043 and higher profit margins before transactions are undertaken no energy savings

length of battery operation

per day 4-hour 4 hour 4-hour 4-hour 6-hour 4-hour

life of battery 15-year 20-year 15-year 15-year 15-year 15 year

augmentation costs to get

to 20-year life without augmentation costs include augmentation costs without augmentation costs without augmentation costs without augmentation costs without augmentation costs

model Use PG&E model use MCPM/JBS model

use MCPM/JBS model but add 3.45% to implement mid-year convention Use PG&E model

Other

lower number is PG&E 2028-43, higher is CLECA 2028-43

Use 7.68% discount rate, not 7.02%

higher number includes PV for energy without energy market revenues for PV


This table also shows the reasons for differences, which include the following:

1. Should a single year or a six-year average be used? (FEA and EPUC)

2. High ROE vs. authorized ROE (PG&E original, PG&E has since corrected)

3. Should the capital cost of the battery be increased? (CLECA)

4. Should the RECC be based on deflation? (CLECA)

5. Should the battery have a four-hour or six-hour capability? (CLECA)

6. Should market revenues be included as offset to capacity costs? (FEA and EPUC)

7. Should market revenues from 2028-2043 be escalated differently than PG&E’s

original estimate? (CLECA)

8. Should the battery have higher variable O&M costs than PG&E estimated,

reducing the value of market energy transactions? (CLECA)

A. Issues that are now Largely Uncontested

There are two previously disputed issues that are now uncontested.

First, CLECA claimed PG&E’s escalation of costs that were an input into the energy

revenue from the battery were overstated. PG&E analyzed the issue and agreed,

though its own calculations were slightly different than CLECA’s. The difference

between the two parties is now relatively small (about $2/kW-year). TURN has revised

its recommendation to use PG&E’s errata method to calculate energy revenues in its

rebuttal calculation.

Second, CLECA raised (in data requests) concerns about TURN not using a mid-year

convention to calculate the RECC. TURN agrees to make this change, the impact of

which raises the cost of the battery by 3.45% [(square root of 1 plus the discount rate)

minus 1]. This revision is also incorporated into TURN’s rebuttal calculation.


B. Return on Common Equity

PG&E’s original testimony used a very high return on common equity (ROE). TURN

identified it and recommended its rejection.39 PG&E’s January update changed the ROE

assumption to its current authorized ROE of 10.25%. As a result, there is no remaining

dispute between TURN and PG&E on this point. However, CLECA, FEA, and EPUC all

based their recommendations on PG&E’s original proposal which contains the

erroneous ROE and those recommendations must be reduced for the correct ROE if any

of their recommendations are considered.

C. Response to FEA/EPUC

Mr. Dauphinais for EPUC states that a capacity resource must generate its own energy:

In the case of PG&E, it has selected a lithium-ion battery, with a four-hour storage capacity, without including the cost of generation facilities. This is an inappropriate basis for representing MGCC because the battery does not generate energy; it only stores electricity produced by an actual generation device and releases it at a later time. In other words, it doesn’t make anything; it just changes the time at which the energy is injected into the network. If a combustion turbine is not a viable choice for determining MGCC, then the lithium-ion battery must be coupled with a generation resource, such as solar panels, in order to provide an actual generation resource.40

FEA/EPUC also removed energy revenues from PG&E’s original case.41 The rationale

(as stated by Mr. Dauphinais for EPUC) is as follows:

It is inappropriate to subtract off forecasted energy rents when determining the long-term MGCC because those energy rents reflect the energy hedge value provided by the resource. Essentially, they reduce the magnitude and/or volatility of the utility’s net cost for energy by offsetting the utility’s cost for energy purchases from the market. Furthermore, unlike fixed capacity payments, forecasted energy rents are not nearly guaranteed or certain. As such, forecasted

39 Prepared Testimony of William Perea Marcus, A. 19-11-019, p. 28, citing PG&E spreadsheet cell. 40 EPUC Direct Testimony, pp. 2-3. 41 With PG&E’s errata case which reduced the cost of the battery by using a lower return on equity, the cost that would be estimated from EPUC’s methodology is $155.66 instead of the $197.72 (before solar) in EPUC’s and FEA’s testimony.


energy rents should be reflected in PG&E’s marginal energy costs not in its MGCC, if at all.42

I disagree in all particulars. Marginal cost theory is not based on a specific plant. It is

based on the MGCC being the least cost of capacity. There is nothing requiring the

capacity to generate energy on its own rather than acquiring it from the grid.

Traditional electric system options over the past 50 years have included pumped

storage hydro and expanded capacity at existing hydro dams even though they do not

provide significant amounts of additional firm energy.

As for the removal of energy revenues, marginal cost theory supports the use of the

least cost of capacity, not the cost of a specific powerplant. As an example, a resource

that obtains revenues from the energy market does not need to obtain all its revenues as

a capacity cost because some of its value is derived from arbitraging energy from lower

load to higher load periods. A Combustion Turbine (CT) is likely not to provide as

much of this value as a battery (though it can have some energy revenue from operating

in very high cost time periods or bidding into a 10-minute reserves market).

Generation technology was different when marginal cost theory was developed over 40

years ago. First, the marginal cost methodology was established in the late 1970s when

CTs were far less efficient than they are today. Heat rates in the range of 15,000

Btu/kWh were common at that time and many units also burned diesel oil. A CT

therefore had little or no energy value and would have been the cheapest cost of pure

capacity at that time. Modern simple-cycle CTs are far more fuel-efficient with heat

rates in the range of 10,000 Btu/kWh or even less. Batteries are even cheaper – with all-

in costs similar to combustion turbines but with considerably more energy revenues.

Finally, as discussed below, a utility can buy capacity from a battery at a considerably

lower price than the prices suggested by EPUC and FEA.

42 EPUC Direct Testimony, pp. 7-8


Further, under most circumstances, the batteries will actually lower the marginal

energy costs, and will not increase them.43 So there is no way to reflect these energy

revenues in marginal energy costs, contrary to Mr. Dauphinais’ position.

To reflect the new markets and emerging technology, energy revenues, even if they

must be forecast,44 should be subtracted from the capacity costs.

D. Response to CLECA

CLECA raised five issues with regard to the calculation of the marginal generation

capacity costs. CLECA’s testimony argues that:

• The MGCC must reflect a Real Economic Carrying Charge (RECC) factor that

properly incorporates negative inflation in the battery cost.45

• The MGCC should reflect the long-term average 2022-2030 growth rate in

energy gross margins for the period 2028-2035.46

• NREL battery cost assumptions should be used.47

• Energy gross margins calculations should be based on a $20/MWh variable

O&M cost.48

• Calculations should be based on a six-hour battery requirement.49

TURN addresses each of these recommendations in the following sections.

43 See discussion in PG&E-2 January Update, pp. 2-38 to 2-40. 44 Forecasting future energy costs is not unprecedented. It was a key component of utility supply planning before deregulation. 45 Testimony of Catherine E. Yap for CLECA, p. 15. 46 Testimony of Catherine E. Yap for CLECA, p. 22. 47 Testimony of Catherine E. Yap for CLECA, p. 19. 48 Testimony of Catherine E. Yap for CLECA, p. 23. 49 Testimony of Catherine E. Yap for CLECA, p. 25.


1. Change MGCC escalation for 2028 and beyond

This issue is now largely unopposed as PG&E (in errata) and TURN (in rebuttal) has

adopted it in principle. Slight differences in PG&E’s calculations from those made by

CLECA (that amount to a little over $2/kW) will not be addressed here.

2. Six Hour Battery Requirement

CLECA asserts a need for a six-hour battery requirement based on battery performance

in a heat storm last August.50 There is no six-hour battery requirement now, after the

storm, adopted by either the CPUC or the California Independent System Operator

(CAISO). Such a requirement should not be adopted in a Phase 2 proceeding for a

single utility and it should be rejected on these grounds alone.

Nevertheless, we should examine the situation more closely. First, in California, the

heat wave was a 1 in 30 weather event, an amount not typically planned for by the

CAISO.51 Additionally, the entire west was affected so that imports were reduced.52

Third, solar resources were reduced due to wildfires (northern California) and clouds

(southern California), which lengthened the time when power was needed late in the

afternoon.53

Battery storage operations were relatively small at about 200 MW. The report

concludes:

Battery storage – During the mid-August events and in early September, there were approximately 200 MW of RA battery storage resources in the CAISO market. It is difficult to draw specific conclusions about fleet performance from such a small sample size. The CAISO will continue to track and understand the collective behavior of the battery storage fleet and work with storage providers

50 CLECA Testimony pp. 25-27. 51 California Independent System Operator (CAISO), California Public Utilities Commission (CPUC), and California Energy Commission (CEC), Final Root Cause Analysis, 2020 Mid-August Extreme Heatwave, January 13, 2021, page 40. 52 Final Root Cause Analysis, pp.. 21-22. 53 Final Root Cause Analysis p. 20.


to effectively incentivize and align storage charge and discharge behavior with the reliability needs of the system.54

*****

It is difficult to draw specific conclusions about fleet performance from such a small sample. The CAISO will continue to track and understand the collective behavior of the battery storage fleet and work with storage providers to effectively incentivize and align storage charge and discharge behavior with the reliability needs of the system. The CAISO has been working to develop enhancements to ensure that as the battery storage fleet size grows the CAISO market can effectively manage them. Several of these changes will only take effect fall 2021. In the interim, the CAISO will ensure storage resource providers understand how the CAISO expects to operate the system so that storage is available when needed to meet net peak demand challenges under stressed summer conditions.55

It appears that the batteries may have been operating for regulation or other ancillary

storage as they were not charging or discharging at full power. See Attachment 8 from

Final Root Cause Analysis.

The Commission and CAISO currently assign Resource Adequacy (RA) credit to

batteries based on their 4-hour discharge capacity.56 PG&E can and does satisfy RA

requirements with battery storage units that are rated based on a 4-hour discharge

period. CLECA’s proposal to rely on a 6-hour discharge period is therefore not in

alignment with the prevailing conventions governing capacity procurement and

existing RA compliance.

In sum, neither the CPUC or CAISO has made a decision to require six-hour batteries. It

is therefore premature and inappropriate to assume the need for six-hour batteries

solely for the purpose of calculating marginal costs in this proceeding. Based on the

available information, CLECA’s position should be rejected.

54 Final Root Cause Analysis, ES-6 and ES-7. 55 Final Root Cause Analysis, p. 60. 56 http://www.caiso.com/Documents/On-PeakDeliverabilityAssessmentMethodology.pdf


3. RECC with Deflation instead of Inflation

CLECA claims that the RECC should be increased because of deflation in the cost of

batteries, which should decline at 3.6% per year instead of increasing at 2% per year.57

The use of an offset to inflation for technological change was developed in the NERA

analysis of marginal costs in the 1970s. It rapidly fell into disuse but the considerations

were that a combustion turbine, then used for capacity (or transmission or distribution

or customer plant), might get cheaper and thereby reduce the amount of inflation.

We now have several issues where marginal cost theory as a whole is on the breaking

edge of being useful for cost allocation.

For capacity costs there is an extreme technological change that strains the use of

marginal cost theory – both a change in the specific plant that is a marginal capacity

resource and the fact that that type of plant is getting cheaper over time relatively

quickly.

For energy costs, the hourly marginal costs provide short-term price signals that are

useful but they are not high enough to support the construction of most renewable

resources, therefore trapping us in a solar cycle that is counterproductive.

So the energy costs are not long-run marginal costs (although they are important for

rate design) and capacity costs are falling rapidly.

Furthermore, there are the following considerations.

There is a resource planning consideration. The utility could find it cost-effective to

spend extra money (for example on demand response programs or other resources)

above and beyond the cost of the battery with the higher RECC. These could be real

excess dollars being spent because the cost of batteries is declining

57 CLECA Testimony, p. 15.


Marginal cost theory was developed with integrated utilities and without competitive

markets. As a result, when the theory is used to analyze an extreme case 45 years after it

was developed, the answer from the theory may not match a price in a competitive

market.

Thus it is not clear that using the price change forecast for batteries as a result of

technological change is reasonable on its face in developing a marginal cost for a battery

in the early 2020s.

On the other side of the coin, we need to come back to the six-hour issue. While a six-

hour battery is not an appropriate choice at this time, it may become reasonable in the

future if and when RA compliance requirements change. Movement from four-hour to

six-hour batteries in approximately a decade (depending on net demand flattening from

earlier batteries, grid changes, and new demand response technologies) could occur.

The move from a four-hour to a six-hour battery is an offsetting cost-increasing change

(increasing costs by about 40-50% for new projects after a certain future time) that

would offset the downward price pressure on batteries themselves. Building more 4-

hour batteries now has the potential to hasten the time when six-hour batteries might be

needed. This issue provides a reason not to use the raw reduction in battery costs.

4. Battery Capital Costs

Which report is better? NREL or Lazard 5.0? Should a 2021 battery cost $1362 or $1205?

That is the question raised by CLECA. CLECA argues that NREL is more reliable,

citing a number of studies, and that Lazard tends to be low.58 CLECA also claims that

NREL is a newer study than Lazard 5.0.59

But Lazard 6.0 was issued a scant few days before intervenors served direct testimony

in this case.60 It shows a 20% decline in battery costs in dollars per kW from 2019 to

58 CLECA testimony, pp. 19-22. 59 CLECA Testimony, pp. 21, 22. 60 Lazard, Levelized Cost of Storage Analysis, Version 6.0, page 5. See Attachment 10.


2020. (Attachment 9 includes the relevant pages from Lazard 5.0, and Attachment 10 are

relevant pages from Lazard 6.0)

Table 3: Lazard Study Cost of 100 MW, 4 Hour Battery ($/kW-year)

While these specific numbers are not commensurate with the calculations performed in

this proceeding (RECC model with California-specific parameters on energy revenues),

the significant cost reduction is indicative.

Given this newer information from Lazard 6, I recommend retaining PG&E’s figure of

$1205/kW in 2021.

5. Minimum Profit Levels for Batteries used in Arbitrage

PG&E uses a minimum profit level of $3/MWh. CLECA includes VOM of $20/MWh,

explaining that:

The Lazard assumptions mentions that the costs for O&M, warranty, and augmentation are $20/MWh.61 Therefore, PG&E has omitted, at minimum, $17/MWh of cost in its energy gross margins analysis. Furthermore, the Lazard $20/MWh figure does not include the minimum profit margin that is required to engage in a transaction so the over estimation of energy gross margins is likely much larger. We have used Lazard’s $20/MWh figure as a conservative estimate.62

61 For the source of this value, CLECA (testimony, p. 21) cites Slide 11 in the Lazard’s Levelized Cost of Storage Analysis Version 5, November 2019. However, we cannot find this figure in either Lazard 5.0 or Lazard 6.0. 62 CLECA Testimony, p. 23.

Low Estimate High Estimate

Lazard 5.0 2019 231 428Lazard 6.0 2020 183 340

reduction -21% -21%

TURN believes that both $3 and $20 per MWh may be arbitrary, although PG&E' s

update, which includes a 20-year life and costs to keep the battery at full power for that

time, is now more consistent with the $3 /MWh figure than its original testimony.

To consider these and other issues, TURN brings forward a specific contract for

analysis.

6. A point of comparison: the Moss Landing Battery Contract

There is a point of comparison that needs to be examined when looking at very high

figures such as those provided by CLECA - a PG&E contract for battery storage at Moss

Landing beginning service at the end of 2021 that was approved by the Commission. It

. RA capacity - costs net of energy values retained by the seller - is

what is being priced in the PG&E, TURN, and CLECA analyses.

TURN' s modeling of a 2021 installation without the ancillary services revenue in 2021

would be $85.98; a 2022 installation would be $70.75.

But to the extent that merchant power is more expensive, there are reasons. A merchant

power developer must take risks that a regulated utility does not take:

• Energy revenues received

• O&Mcosts

• Capital costs

63 PG&E, Dynegy - Visb:a MOSSlOO Energy Storage Long Term Resource Adequacy Agreement (LT RAA) (Confidential), page 5. M PG&E Independent Evaluator Report (Confidential), page 32.



• The creditworthiness of the utility over the contract life

Additionally, a merchant developer tends to have higher ROE requirements and a

different capital structure than a utility. Its tax considerations are also different. In a

cash flow analysis, the developer takes as current cash the tax deductions that a utility

must normalize. Additionally, energy revenues are part of its taxable income.

In sum, this contract, while shifting the burden of risk and return from the ratepayers to

the contractor and charging ratepayers more for that shift, tends to provide support for

the analysis of TURN and PG&E more than it does the much higher costs estimated by

CLECA and FEA/EPUC.

7. Summary

All of the information presented above supports a capacity cost between $55 and $60

per kW (at generation voltage, before 15% reserve margin), a range captured by PG&E’s

corrected numbers and TURN’s revised numbers. TURN’s estimate of $57.40 is based

on its original numbers corrected to use a mid-year convention and to apply PG&E’s

reduction to 2028-2043 energy revenue offsets.

Table 4: TURN’s Marginal Generation Capacity Cost Revised for Rebuttal Case

CCGTCost Revenue Net Fixed Cost Capacity Cost Discount NPV

2021 163.13 (85.92) 77.21 34.17 77.21 1.0000 77.21 2022 153.08 (82.34) 70.75 34.75 70.75 0.9328 65.99 2023 143.65 (84.57) 59.09 34.94 59.09 0.8702 51.42 2024 135.94 (86.12) 49.82 35.25 49.82 0.8117 40.44 2025 129.73 (87.91) 41.81 35.13 41.81 0.7572 31.66 2026 124.82 (90.37) 34.45 35.42 35.42 0.7064 25.02

5.0783 291.74 Annualized 57.45

plus 15% RM 8.62 Capacity Cost 66.07

Battery


IV. Marginal Energy Costs

In its letter dated December 30, 2020, PG&E agreed in principle with AECA that there

should be an adder for short-run renewable costs to marginal energy costs. Changes in

bundled customer demand have led to PG&E selling excess renewable energy to other

load-serving entities. The approximate cost adder is $5.19/MWh. However, PG&E did

not include this value in its January 15 Update. TURN supports the inclusion of this

cost and recommends that it be included eventually.

Table 5: PG&E’s and TURN’s Marginal Energy Costs by Time Period

Revised for Rebuttal Case

PG&E

Transmission

Primary

Distribution

Secondary

Distribution Transmission

Primary

Distribution

Secondary

Distribution

summer Peak 5.841 5.951 6.246 6.459 6.571 6.871

Summer Partial Peak 4.378 4.46 4.681 4.971 5.055 5.280

Summer Off-Peak 2.783 2.836 2.976 3.349 3.403 3.546

Winter Partial Peak 5.013 5.107 5.36 5.617 5.713 5.970

Winter Off Peak 2.922 2.976 3.124 3.491 3.546 3.696

Spring Super Off Peak -0.041 -0.041 -0.043 0.477 0.477 0.475

TURN (ancillary services and renewable short-term)