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BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Order Instituting Rulemaking to Create a Consistent Regulatory Framework for the Guidance, Planning, and Evaluation of Integrated Distributed Energy Resources. Rulemaking 14-10-003 Filed October 2, 2014 OPENING COMMENTS OF PACIFIC GAS AND ELECTRIC COMPANY (U 39 M), SOUTHERN CALIFORNIA EDISON COMPANY (U 338 E), SOUTHERN CALIFORNIA GAS COMPANY (U 904 G), AND SAN DIEGO GAS & ELECTRIC COMPANY (U 902 M) ON ADMINISTRATIVE LAW JUDGE’S RULING SEEKING RESPONSES TO QUESTIONS AND COMMENT ON STAFF AMENDED PROPOSAL ON SOCIETAL COST TEST FADIA KHOURY CATHY A. KARLSTAD Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY 2244 Walnut Grove Avenue Rosemead, CA 91770 Telephone: (626) 302-1096 Facsimile: (626) 302-3990 E-mail: [email protected] EDWARD L. HSU Attorney for SOUTHERN CALIFORNIA GAS COMPANY 555 West 5 th Street, GT 14 E7 Los Angeles, California 90013 Telephone: (213) 244-8197 Facsimile: (213) 629-9620 Email: [email protected] Dated: April 20, 2018 CHRISTOPHER J. WARNER MARY A. GANDESBERY Attorneys for PACIFIC GAS AND ELECTRIC COMPANY 77 Beale Street, B30A San Francisco, CA 94120 Telephone: (415) 973-0675 Facsimile: (415) 973-5520 E-mail: [email protected] JONATHAN J. NEWLANDER Attorney for SAN DIEGO GAS & ELECTRIC COMPANY 8330 Century Park Court, CP32D San Diego, CA 92123-1530 Telephone: (858) 654-1652 Facsimile: (619) 699-5027 E-mail: [email protected]

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BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA

Order Instituting Rulemaking to Create a Consistent Regulatory Framework for the Guidance, Planning, and Evaluation of Integrated Distributed Energy Resources.

Rulemaking 14-10-003

Filed October 2, 2014

OPENING COMMENTS OF PACIFIC GAS AND ELECTRIC

COMPANY (U 39 M), SOUTHERN CALIFORNIA EDISON

COMPANY (U 338 E), SOUTHERN CALIFORNIA GAS

COMPANY (U 904 G), AND SAN DIEGO GAS & ELECTRIC

COMPANY (U 902 M) ON ADMINISTRATIVE LAW JUDGE’S

RULING SEEKING RESPONSES TO QUESTIONS AND

COMMENT ON STAFF AMENDED PROPOSAL ON SOCIETAL

COST TEST

FADIA KHOURY

CATHY A. KARLSTAD

Attorneys for

SOUTHERN CALIFORNIA EDISON

COMPANY

2244 Walnut Grove Avenue

Rosemead, CA 91770

Telephone: (626) 302-1096

Facsimile: (626) 302-3990

E-mail: [email protected]

EDWARD L. HSU

Attorney for

SOUTHERN CALIFORNIA GAS

COMPANY

555 West 5th

Street, GT 14 E7

Los Angeles, California 90013

Telephone: (213) 244-8197

Facsimile: (213) 629-9620

Email: [email protected]

Dated: April 20, 2018

CHRISTOPHER J. WARNER

MARY A. GANDESBERY

Attorneys for

PACIFIC GAS AND ELECTRIC

COMPANY

77 Beale Street, B30A

San Francisco, CA 94120

Telephone: (415) 973-0675

Facsimile: (415) 973-5520

E-mail: [email protected]

JONATHAN J. NEWLANDER

Attorney for

SAN DIEGO GAS & ELECTRIC COMPANY

8330 Century Park Court, CP32D

San Diego, CA 92123-1530

Telephone: (858) 654-1652

Facsimile: (619) 699-5027

E-mail: [email protected]

TABLE OF CONTENTS

Page

-i-

I. INTRODUCTION ............................................................................................................. 1

II. DISCUSSION .................................................................................................................... 2

A. General Comments on Amended Staff Proposal. .................................................. 2

B. Response to Questions on Amended Staff Proposal. ............................................. 3

1. Explain why the Commission should or should not adopt the

modified TRC and PAC tests as replacements for the existing TRC

and PAC tests. ............................................................................................ 3

2. Explain why the Commission should or should not also adopt a

modified Ratepayer Impact Measure (RIM) test that is modified in

the same manner as the TRC and PAC tests. ............................................. 8

3. Explain why the Commission should or should not adopt the

Societal Cost Test as an additional test to be used initially for

information purposes only. If the Commission adopts the Societal

Cost Test as an additional test, explain why the Commission

should or should not then allow each resource proceeding to

determine how (if at all) to use the test in decision-making. ..................... 8

4. Explain why the Commission should or should not require all

distributed energy resources activities that currently use the TRC

and PAC tests to instead use the modified TRC, modified PAC,

and Societal Cost tests. .............................................................................. 9

5. Explain why the Commission should or should not revise its

nomenclature such that the value for the greenhouse gas adder used

in the modified TRC and PAC tests is referred to as the “avoided

cost of carbon abatement” and the greenhouse gas adder value used

in the Societal Cost Test is referred to as the “avoided social cost

of carbon.”................................................................................................ 10

6. Explain why the Commission should or should not determine the

“avoided cost of carbon abatement” in R.16-02-007 Explain why

the Commission should or should not adjust this value in order to

avoid double counting. ............................................................................. 11

7. Explain why the Commission should or should not adopt the high

impact value, developed by the Interagency Working Group on

Social Cost of Greenhouse Gases, as the “social cost of carbon.” .......... 14

8. Explain why the Commission should or should not adopt a 3

percent discount rate for the Societal Cost Test....................................... 15

TABLE OF CONTENTS (continued)

Page

-ii-

9. Explain why the Commission should or should not use the USEPA

COBRA Tool to compute and adopt an Interim Air Quality Adder

until a more robust model can be developed. If you believe that

another model should be used, explain why and provide a detailed

description of how that model should be used instead. ........................... 16

10. Explain why the Commission should or should not authorize Staff

to continue to study and analyze improvements to the distributed

energy resources cost-effectiveness framework, including the

development of a common resource valuation method, and issue

reports on its findings and subsequent proposals. Are there

additional improvements that should be considered? .............................. 17

III. CONCLUSION ................................................................................................................ 19

- 1 -

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA

Order Instituting Rulemaking to Create a Consistent Regulatory Framework for the Guidance, Planning, and Evaluation of Integrated Distributed Energy Resources.

Rulemaking 14-10-003

Filed October 2, 2014

OPENING COMMENTS OF PACIFIC GAS AND ELECTRIC

COMPANY (U 39 M), SOUTHERN CALIFORNIA EDISON

COMPANY (U 338 E), SOUTHERN CALIFORNIA GAS

COMPANY (U 904 G), AND SAN DIEGO GAS & ELECTRIC

COMPANY (U 902 M) ON ADMINISTRATIVE LAW JUDGE’S

RULING SEEKING RESPONSES TO QUESTIONS AND

COMMENT ON STAFF AMENDED PROPOSAL ON SOCIETAL

COST TEST.

I. INTRODUCTION

In compliance with the Administrative Law Judge’s Ruling Seeking Responses to

Questions and Comment on Staff Amended Proposal on Societal Cost Test (“Ruling”), dated

March 14, 2018, Pacific Gas and Electric Company (“PG&E”), San Diego Gas & Electric

Company (“SDG&E”), Southern California Gas Company (“SoCalGas”) and Southern California

Edison Company (“SCE”) (collectively, the “Joint Utilities”) submit their opening comments.1/

The Joint Utilities have concerns with many aspects of the Energy Division Staff Proposal

Addendum #2 (“Amended Staff Proposal”). A key principle for meeting the state’s 2030

greenhouse gas (“GHG”) goals is least-cost, resource-neutral GHG reductions. However, the

Amended Staff Proposal may lead to the opposite result by creating greater divergence in resource

valuation by using a higher GHG value than would be applicable to conventional resources for the

distributed energy resource (“DER”) cost-effectiveness tests. The proposals in the Amended Staff

Proposal follow an earlier California Public Utilities Commission (“Commission” or “CPUC”)

decision to evaluate the resources using only long-term capacity prices, whether or not the new

1/ Pursuant to Rule 1.8(d), counsel for SDG&E, SoCalGas, and SCE have authorized counsel for

PG&E to file and serve these joint opening comments on their behalf.

- 2 -

DERs are actually avoiding the acquisition of long-term capacity by the investor-owned utilities

(“IOUs”).2/ The application of the results of the modified cost-effectiveness tests from the

Amended Staff Proposal could lead to higher rates, for which there would be clear losers – non-

participating customers, including low-income customers; delayed GHG reductions in other

sectors; and the most cost-effective clean energy solutions, as their market is reduced to

accommodate approaches subject to the more favorable valuation methodology.

II. DISCUSSION

A. General Comments on Amended Staff Proposal.

The following are the Joint Utilities’ recommendations for addressing the issues identified

above. These issues are discussed further in responses to the questions. The Joint Utilities

request that the Amended Staff Proposal be revised as follows:

Adopt the Integrated Resource Plan (“IRP”) GHG Planning Prices, instead of the

proposed IRP DER GHG Adder Prices, and update these prices in the 2019 IRP to

address DER optimization limitations in the 2017 IRP.

Maintain versions of the total resource cost (“TRC”), program administrator cost

(“PAC”), and ratepayer impact measure (“RIM”) tests that use the cap-and-trade

allowance price forecast to ensure policymakers understand how cost-effective a

policy is relative to the actual costs incurred by customers.

Institute ex-post reviews of the avoided cost calculator (“ACC model”) using

actual market data to enable study of the level of above or below market costs.

Limit the GHG adder to the electric sector.3/

Use the Societal Cost Test (“SCT”) for informational purposes only and require

changes to how it is used be made in the Integrated Distributed Energy Resources

2/ D.16-06-007.

3/ This proposal is intended to highlight that the IRP has been limited to electric sector planning to

date and that it would be inappropriate to apply an output from one sector to planning in another

sector. However, if these values are used in fuel substitution programs, further discussion is

warranted on the appropriate GHG sectoral value to use in those programs.

- 3 -

(“IDER”) proceeding, not individual proceedings regarding the IOU’s DER

programs.

Adopt reasonable SCT values for the GHG and air quality adders, not the highest

values available.

Avoid double counting by aligning the ACC model with IRP values for energy,

capacity, Renewables Portfolio Standard (“RPS”), and GHG.

B. Response to Questions on Amended Staff Proposal.

The Joint Utilities respond below to the specific questions in the Ruling regarding

Addendum No. 2.

1. Explain why the Commission should or should not adopt the modified

TRC and PAC tests as replacements for the existing TRC and PAC tests.

The Joint Utilities propose that the Commission modify the existing TRC and PAC tests

by approving the use of the GHG Planning Prices generated in the IRP proceeding, R.16-02-007,4/

as the societal GHG value,5/ instead of the DER GHG Adder values approved in the IRP

proceeding.6/ Unmodified versions of the tests that use the California Energy Commission’s

(“CEC”) IEPR cap-and-trade forecast for the GHG value should also be maintained. Further, the

modified versions of the tests should only be used for electric demand-side management

programs, not natural gas programs. Finally, the Commission should require the avoided costs to

be examined on an ex-post basis and be compared to observed market conditions. Each of these

points is discussed further below.

GHG Abatement Values: The GHG values proposed by Staff for use in the modified

versions of the TRC/PAC tests (the IRP DER GHG adder values) should not be adopted. These

4/ D.18-02-018, p. 116.

5/ The Joint Utilities distinguish between GHG values as follows:

GHG C&T Compliance Value: the forecast of cap-and-trade allowance selling prices that the

ACC model derives from the Integrated Energy Policy Report (“IEPR”).

Societal GHG Value: the additional value placed on GHG emissions beyond the GHG C&T

Compliance Value. This can be an abatement value or damages value.

6/ D.18-02-018, p. 118.

- 4 -

values are not the best measure of the GHG costs avoided by DERs that customers would incur in

the absence of the DERs. Instead, the Joint Utilities recommend adopting modified versions of

the TRC/PAC with the new set of GHG Planning Prices produced from the 2019 IRP modeling.

In D.18-02-018 (the “IRP Decision”), the Commission established two different GHG

prices – the DER GHG Adder for use in the avoided cost calculator and the GHG Planning Prices

for use in IRP.7/ The DER GHG Adder is based on drawing a straight-line between the cap-and-

trade program’s Allowance Price Containment Reserve (“APCR”) in 2018 and the 2030 GHG

price developed using the RESOLVE model. Because this line was arbitrarily drawn, it includes

values that have no factual basis. Per Energy Division’s analysis, at no point before 2027 does the

IRP-modeled GHG abatement price rise from the cap-and-trade floor. The APCR also remains

below the proposed DER GHG Adder in all years following 2018. This means that the DER

GHG Adder values effectively exceed any possible GHG abatement mechanism values in place

between 2018 and 2030. In addition, since the IRP GHG Planning Prices mostly follow the cap-

and-trade floor prices until 2027, electric customers will be paying much higher prices for DER

GHG abatement than supply-side GHG abatement, which uses the lower LSE GHG Planning

Prices. The difference between these two IRP forecasts is shown in Figure 1 below:

7/ D.18-02-018, pp. 116-118.

- 5 -

Figure 1: IRP GHG Planning Prices and IRP DER GHG Adder (real 2016$)

The Commission noted that a reason for identifying a higher GHG price forecast for DERs

was because many DERs were not optimized as candidate resources in the IRP, and therefore the

GHG abatement values did not accurately reflect the impact of DERs.8/ There are plans to

incorporate additional DERs as candidate resources in the 2019 IRP cycle and IRP Modeling

Advisory Group meetings will address this issue.9/ Accordingly, instead of setting a precedent to

use unfounded higher values for DER cost-effectiveness, the Commission should adopt modified

versions of the TRC/PAC after the 2019 IRP has produced one GHG shadow price for all

resources – the GHG Planning Prices. This will ensure that customers do not pay above-market

prices for GHG abatement that could be met by lower cost supply-side resources. In the interim,

the Commission could either continue to use the Interim GHG Adder prices or switch to the 2017

IRP GHG Planning Prices.

8/ D.18-02-018, p. 155.

9/ IRP Modeling Advisory Group Draft 2018 Meeting Schedule and Agenda Topics, available at:

http://www.cpuc.ca.gov/uploadedFiles/CPUCWebsite/Content/UtilitiesIndustries/Energy/Energy

Programs/ElectPowerProcurementGeneration/irp/2018/MAG%20Meeting%20Schedule%202018

_Public_2018-02-27.pdf.

$0

$20

$40

$60

$80

$100

$120

$140

$160

IRP LSE GHG Planning Prices IRP DER GHG Adder

- 6 -

Maintain Unmodified Versions of the Tests: If the Commission decides to adopt modified

versions of the TRC/PAC with the DER GHG Adder, the Commission should also maintain

unmodified versions of the tests that use the GHG value from the forecast of cap-and-trade

allowance selling prices. These are important versions of the tests to maintain to inform policy

decisions, as they represent the actual costs avoided by customers. One example of the need for

these unmodified tests is Public Utilities Code Section 2827.1(b)(4), which requires total benefits

to equal total costs.10/ Unless these alternate tests are maintained and made available for policy

decisions, customers could be harmed through the approval of Staff’s proposal as it will indicate

that DERs are more cost-effective than actual market conditions would indicate – leading to

increased electric rates to pay for non-cost-effective DERs.

Adoption of inaccurate or inflated values can also have implications beyond development

of DER goals or tariffs. For instance, in its opening written testimony in R.17-06-026, California

Community Choice Association (“CalCCA”) proposes using generation capacity, ancillary

services, and Renewable Energy Certificate (“REC”) values from the ACC model for cost

allocation purposes for the Power Charge Indifference Adjustment (“PCIA”) benchmarks.11/ This

is despite the fact that D.16-06-007 ended the practice of using a resource balance year to

determine capacity value for DERs in the calculator, resulting in the calculator using the long-run

value of capacity (the cost of a new simple cycle gas turbine) for every year in the forecast, as

opposed to using market-based prices for Resource Adequacy. While the ACC model is intended

for DERs only, the CalCCA proposal underscores the importance of adopting market-based

values so that use of distorted values does not lead to improper use in areas outside DER cost-

effectiveness.

10/ Pub. Util. Code Section 2827.1(b)(4) reads: “Ensure that the total benefits of the standard contract

or tariff to all customers and the electrical system are approximately equal to the total costs.” In

R.14-07-002, the Commission used the Standard Practice Manual tests as a measure of

compliance with this requirement for the net energy metering successor tariff.

11/ See Prepared Direct Testimony of CalCCA, R.17-02-026 (Apr. 2, 2018).

- 7 -

Modified versions of the TRC and PAC should only apply to the electric sector because

the IRP only addresses the electric sector.12/ If the DER GHG Adder is approved for the avoided

cost calculator, it should only apply to electric programs, not natural gas programs. 2017 IRP

planning was limited to the electric sector only; therefore, it would not be appropriate to apply

outputs from an electric sector planning exercise to other sectors, like natural gas, as is being

proposed for the modified TRC, PAC, and RIM, to other sectors like natural gas. Those other

sectors should be subject to the avoided costs experienced in those sectors. For natural gas sector

programs, such as natural gas energy efficiency (“EE”) programs and California Solar Initiative

(“CSI”) thermal that are subject to the TRC, PAC, and RIM tests, the GHG avoided cost benefits

customers would receive are based on the California Air Resources Board (“CARB”) cap-and-

trade program. Therefore, natural gas programs should continue to use GHG prices from a cap-

and-trade program market forecast like the IEPR forecast that is already included in the avoided

cost calculator.

Ex-post Evaluation: The Commission should begin to assess the calculator on an ex-post

basis to evaluate the assumptions and inputs with observed market conditions and identify above

or below market costs. To date, the calculator has only been prospectively defined. The proposed

modified versions of the test would include GHG values that are much higher than those applied

to supply-side resources or those found in the cap-and-trade market. This risks further divorcing

the values in the calculator from observed market conditions. The calculator already includes a

long-run cost of capacity, which is significantly higher than market-based prices, as explained in

the sections above. An annual ex-post true up of the calculator relative to market prices for the

avoided costs is an opportunity to assess how well the calculator represents market conditions and

the extent to which California policy favors DERs. This should be performed prior to the annual

12/ This proposal is intended to highlight that the IRP has been limited to electric sector planning to

date and that it would be inappropriate to apply an output from one sector to planning in another

sector. However, if these values are used in fuel substitution programs, further discussion is

warranted on the appropriate GHG sectoral value to use in those programs.

- 8 -

update and stakeholders should have an opportunity to comment on improvements that could be

undertaken in the update to better align the calculator with the findings of the ex post assessment.

2. Explain why the Commission should or should not also adopt a modified

Ratepayer Impact Measure (RIM) test that is modified in the same manner

as the TRC and PAC tests.

Consistent with the response to Question No. 1, the Commission should only adopt a

modified RIM test if that test uses the IRP GHG Planning Prices. The Standard Practice Manual

states: “The Ratepayer Impact Measure (RIM) test measures what happens to customer bills or

rates due to changes in utility revenues and operating costs caused by the program.”13/ A

modified version of the RIM test with much higher GHG values than the cap-and-trade allowance

prices or the IRP GHG Planning Prices, such as the DER GHG Adder would result in inflated

avoided cost benefits and not accurately measure customer rate impacts.

Should the Commission make the decision to modify the RIM test to include the DER

GHG Adder, the Joint Utilities strongly recommend, consistent with comments made in response

to Question No. 1, that the Commission also continue to maintain an unmodified version of the

RIM test without the DER GHG Adder. This would provide an understanding of the actual rate

impacts of the intervention in question, which is the intent of the RIM test.

3. Explain why the Commission should or should not adopt the Societal Cost

Test as an additional test to be used initially for information purposes

only. If the Commission adopts the Societal Cost Test as an additional test,

explain why the Commission should or should not then allow each

resource proceeding to determine how (if at all) to use the test in decision-

making.

If the Commission adopts a SCT, it should clearly state that the test is to be used for

informational purposes only and not for approving program budgets, procurement decisions, or

tariffs. Including the SCT with the cost of carbon value, that even Staff acknowledges is

“controversial, complicated and uncertain,”14/ would result in a cost-effectiveness threshold that

13/ California Standard Practice Manual, p. 13 (Oct. 2001).

14/ Amended Staff Proposal, p. 7.

- 9 -

would lead to over-procurement of DERs compared to other, more cost-effective GHG-free

resources (i.e., utility-scale renewables). Therefore, the Commission should not allow the

decisionmaker(s) in each resource proceeding to determine how to use the test. There should be

no exceptions for the IOUs’ DER programs.15/ This includes low income programs, where the

test could be used, but for informational purposes only.

Use of the test for purposes other than informational would result in the use of different

valuation criteria to determine California’s resource portfolio and associated program funding.

Doing so would lead to under-procurement of economic resources, over-procurement of

uneconomic resources, and unnecessarily expensive electric rates. These high electric rates would

imperil meeting state GHG goals in other sectors like transportation, where GHG reductions

partly depend on low electric rates to spur customer adoption of electric vehicles.

4. Explain why the Commission should or should not require all distributed

energy resources activities that currently use the TRC and PAC tests to

instead use the modified TRC, modified PAC, and Societal Cost tests.

The Joint Utilities support requiring calculation and use of the modified tests if they are

based on the IRP GHG Planning Prices. See response to question #1, above, for further

discussion.

The Joint Utilities object to use of the SCT to establish program budgets or DER

incentives or other compensation. The SCT should only be used for informational purposes, since

the SCT represents a broader perspective than that of the utility, customers, or participants,

includes costs without a nexus to utility rates, and would impose excess costs on IOU customers

that are not experienced by others in the state – for instance, publicly-owned utility (“POU”)

customers, customers that use alternate fuels, and other sectors like transportation.

15/ There are some programs where use of the SCT is reasonable for budget decisions, but these are

outside Commission jurisdiction – e.g., proper use of state-level funds like CARB’s Unallocated

Allowance Investment Plan and Prop 39 funds.

- 10 -

5. Explain why the Commission should or should not revise its nomenclature

such that the value for the greenhouse gas adder used in the modified TRC

and PAC tests is referred to as the “avoided cost of carbon abatement” and

the greenhouse gas adder value used in the Societal Cost Test is referred to

as the “avoided social cost of carbon.”

The Commission should not revise the name of the GHG adder to the “avoided cost of

carbon abatement” because the DER GHG Adders developed from the IRP proceeding and

approved for use in the IDER proceeding in the IRP Decision do not represent avoided GHG

abatement costs. To the contrary, these costs stem from an interpolation arbitrarily starting at the

APCR and ending at the 2030 GHG price developed using the RESOLVE model. While the Joint

Utilities agree that the avoided cost of carbon abatement is the correct value to use in the modified

TRC and PAC tests, the DER GHG Adder does not actually represent the “avoided cost of carbon

abatement.” Instead, should the Commission choose to use the DER GHG Adder provided by the

IRP for DERs, it should defer to the nomenclature provided in the Commission’s IRP decision

and call such adder the “GHG Adder for use in demand-side cost-effectiveness analyses,” or the

“DER GHG Adder” for short. This nomenclature is critical to differentiate the inflated DER

GHG Adders from the GHG Planning Prices given for IRP development and to transparently

identify the additional value given to DERs over and above that provided for supply-side

resources.

The GHG Planning Prices adopted for use in the IRP are a closer approximation to the

“avoided cost of carbon abatement.” The Joint Utilities believe the truly accurate name for the

GHG Planning Price would be the “CPUC-jurisdictional electric sector marginal abatement cost.”

The qualifier of “CPUC-jurisdictional electric sector” is required since the RESOLVE output of

$150/ton is relevant only for CPUC-jurisdictional electric sector planning and does not represent a

realistic view of future ARB cap-and-trade market prices, which represent the economy-wide

marginal abatement cost.

For these reasons, the Commission should only use the term “CPUC-jurisdictional electric

sector marginal abatement cost” for the GHG Planning Price and should use the term “DER GHG

Adder” to represent the GHG adder proposed to be used in the modified TRC and PAC tests.

- 11 -

This nomenclature difference could be eliminated after the 2019 IRP, if the 2019 IRP identifies

one GHG price to be used across supply and demand-side resources.

If the Commission does adopt the U.S. Environmental Protection Agency’s (“USEPA”)

social cost of carbon as the GHG adder value in the SCT, the Joint Utilities are not opposed to

referring to the GHG adder as the “avoided social cost of carbon.”

6. Explain why the Commission should or should not determine the “avoided

cost of carbon abatement” in R.16-02-007 Explain why the Commission

should or should not adjust this value in order to avoid double counting.

In general, the Joint Utilities support the IRP as the proceeding in which to plan for and

conduct the associated modeling for the electric sector GHG planning target. The Joint Utilities

also support IRP as the venue for providing guidance to load-serving entities (“LSEs”) and

Commission proceedings regarding GHG targets and/or planning prices. However, the Joint

Utilities strongly disagree with the approach taken in D.18-02-018 to set a GHG Adder for DER

cost-effectiveness that diverges from the GHG Planning Price provided for supply-side resource

planning in LSE IRPs. This creates an unequal playing field among resources that threatens the

achievement of state goals at the least cost.

The Commission in D.18-02-018 did not find that the DER GHG Adder represents the

“avoided cost of carbon abatement.” Instead, it created two different sets of GHG values: the

“GHG Planning Price” and the “DER GHG Adder,” and clarified that the “DER GHG Adder”

represents “a compromise designed to give market and timing certainty to DER providers,” not a

carbon abatement cost.16/

Regarding the question of whether to adjust the IRP-derived values to avoid double

counting, the Joint Utilities strongly agree this is needed to avoid factual error associated with

misapplying the outputs of the RESOLVE model. The following adjustments must be made:

Adjustment for cap and trade allowance prices: The Joint Utilities agree with

ED’s proposed approach. Since the $150/ton in 2030 value included a forecast of

16/ D.18-02-018, p. 118.

- 12 -

cap-and-trade carbon allowances, the DER GHG Adder value should be adjusted

to separate out the “adder” portion and the cap and trade portion.

Cost Vintaging: The Joint Utilities agree with Staff that this must be addressed, as

well as ensuring consistency between the use of real dollars in RESOLVE versus

nominal dollars in the ACC.

Other avoided costs: In general, since the $150/ton in 2030 value was extracted

from the RESOLVE optimization shadow price, specific adjustments are needed to

prevent double counting. The Joint Utilities disagree with the reasoning Staff

provided, which they claim only applies to the avoided RPS value. Instead, all

avoided costs must be aligned between the models, including energy and

capacity values. This is because the RESOLVE shadow price represents the

“make-whole payment” needed for the marginal GHG-free resource added to meet

the 42 MMT GHG constraint. This make-whole payment is the remaining

difference between a GHG-free resource’s cost and the avoided costs captured in

the RESOLVE optimization’s objective function, which include avoided energy,

capacity, and RPS. If the ACC model assumes higher avoided costs than

RESOLVE, the only way to avoid double counting is to either align the

avoided costs or reduce the GHG Adder proportionately.

o Avoided RPS: RESOLVE shows $0/MWh marginal RPS costs in all years

through 2030, since there is no avoided RPS value for marginal GHG-free

resource additions once GHG is a binding constraint in the model, driving

GHG-free resources above the RPS floor. Hence, the Joint Utilities agree

that the ACC model should be adjusted to remove avoided RPS.

o Avoided capacity: RESOLVE shows $0/kW-yr. marginal capacity

(“PRM”) costs in all years through 2030. To utilize the GHG Adder in the

ACC model, either capacity values must be adjusted to match RESOLVE,

or the GHG Adder reduced proportionately. This may require the

- 13 -

Commission re-examining its treatment of the Resource Balance Year in

the IDER proceeding, to be consistent with the approach taken in IRP. As

shown in Table 2 below, if RESOLVE assumed a positive avoided cost for

system capacity, the corresponding marginal GHG cost is reduced (for the

25-year gas retirement RESOLVE scenario, this increases the marginal

PRM cost to $75/kW-yr. and decreases the GHG shadow price by half to

$74/tCO2).

o Avoided energy: RESOLVE’s energy values are based on a 42MMT

scenario, with ~59% RPS in 2030. To utilize the GHG Adder in the ACC

model, energy values and hourly marginal heat rates must be adjusted to

match the IRP Reference System Plan, or the GHG Adder reduced

proportionately.

Table 1

RESOLVE model outputs for the 42mmt Reference System Plan,

showing zero avoided costs for RPS and system capacity (“PRM”)

in 2030.

* Note: Marginal GHG Cost represents the RESOLVE shadow price, once the ARB cap and trade prices

are added, this leads to $150/tCO2 in 2030.

Active Scenario Name 42mmt_Ref_20170831

Unit 2018 2022 2026 2030

Marginal RPS Cost $/MWh -$ -$ -$ -$

Marginal GHG Cost * $/tCO2 -$ -$ -$ 121$

Marginal PRM Cost $/kW-yr. -$ -$ -$ -$

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Table 2

RESOLVE model outputs for the 42mmt case with high gas

retirements, showing how higher system capacity values (“PRM”)

in 2030 drive lower marginal GHG costs.

* Note: Marginal GHG Cost represents the RESOLVE shadow price, once the ARB cap and trade prices

are added, this leads to $103/tCO2 in 2030.

7. Explain why the Commission should or should not adopt the high impact

value, developed by the Interagency Working Group on Social Cost of

Greenhouse Gases, as the “social cost of carbon.”

The Commission should not adopt the “high impact” value, as it conflicts with Federal and

CARB approaches, as well as US Academies’ recommendations. If the Commission is going to

utilize a single trajectory for the Social Cost of Carbon (“SCC”), it should use the “central value”

trajectory from the Interagency Working Group (“IWG”) report at the discount rate decided on in

question #8. These central values were utilized in Federal rulemakings through 2016, and by

CARB in the 2030 Scoping Plan.17/ If the Commission is going to utilize multiple values, it

should follow the US Academies’ recommendation of using values from both the high and low

end of the SCC distribution from the IWG; 18/as their 2016 assessment states: “Finally, the

committee recommends that the IWG provide symmetric treatment of both low and high values

from the frequency distribution of SCC estimates conditional on each discount rate.”19/

17/ California’s 2017 Climate Change Scoping Plan, CARB, November 2017, p. 39-40; download

available at: https://www.arb.ca.gov/cc/scopingplan/scoping_plan_2017.pdf

18/ Assessment of Approaches to Updating the Social Cost of Carbon: Phase 1 Report on Near-Term

Update, The National Academies, 2016, p. 1-2, download available at:

http://www8.nationalacademies.org/cp/projectview.aspx?key=49733

19/ We support reevaluating SCC estimates periodically to incorporate new information as research

progresses; US Academies’ provided some useful recommendations going forward on updating

estimates of the SCC and we are tracking Resources for the Future’s (RFF) SCC project that is

helping fill the gap created by the disbandment of the IWG; for RFF work, see

http://www.rff.org/research/collection/rffs-social-cost-carbon-initiative

Active Scenario Name 42mmt_Ref_25yr_gasretirement_20170831

Unit 2018 2022 2026 2030

Marginal RPS Cost $/MWh -$ -$ -$ -$

Marginal GHG Cost * $/tCO2 -$ -$ -$ 74$

Marginal PRM Cost $/kW-yr. -$ -$ -$ 75$

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The SCT should use GHG avoided costs based on the lower of either the carbon

abatement or damage cost. It is not socially optimal to choose resource portfolios with higher

avoided GHG costs than necessary to abate or than the social damage cost. As an example, if the

cost of abatement is less than damage costs, then it is economically optimal to abate. If the cost of

abatement is higher than the damage costs, it is not optimal to abate since the carbon reductions

are worth less than their costs. For this reason, should the Commission create an SCT that utilizes

a damages-based avoided GHG cost that is higher than the cost of abatement, this test should not

be used for Commission resource planning or policy decisions.

8. Explain why the Commission should or should not adopt a 3 percent

discount rate for the Societal Cost Test.

The Joint Utilities do not support the Staff’s proposal to use a social discount rate because

it is inappropriate for an intragenerational cost benefit analysis of alternative DER assets. Social

discount rates are intended to evaluate the tradeoff among generations, often over hundreds of

years (e.g. intergenerational discounting), of different levels of investment and consumption as

those are impacted by government policies. The purpose of the SCT, on the other hand is to

evaluate the costs and benefits of DERs, as those costs are incurred by society over the expected

life of the DER; it is not the purpose for which the low social discount rates were intended.

Should the Commission proceed with adopting a social discount rate for the Societal Cost

Test, the Joint Utilities recommend that the Commission adopt the 5% discount rate noted in the

Interagency Working Group on Social Cost of Greenhouse Gases.20/ There is uncertainty

surrounding the economics of climate change, which makes it difficult to place a monetary value

on environmental services. One way to address this uncertainty would be to use a higher social

discount rate in the short and medium term (10-25 years), and then consider a declining discount

rate in the long run if there is more certain evidence for it in the future. The Joint Utilities believe

20/ Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory

Impact Analysis Under Executive Order 12866, The Interagency Working Group on Social Cost

of Greenhouse Gases, the United States Government, Table A1 (Aug. 2016).

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that the use of a higher discount rate (e.g. 5% vs. 3% real) may help in alleviating concerns that

the SCT will result in projects being approved that are not cost-effective, and may not be

financeable, and will also result in a misallocation of resources within utility operations.

9. Explain why the Commission should or should not use the USEPA

COBRA Tool to compute and adopt an Interim Air Quality Adder until a

more robust model can be developed. If you believe that another model

should be used, explain why and provide a detailed description of how that

model should be used instead.

The Joint Utilities recommend that the Commission not implement the USEPA’s COBRA

tool to compute and adopt an air quality adder. Instead, the Commission should explore other

tools such as BenMAP that could provide more accurate modeling of air quality impacts. This

recommendation is based on two major points: (1) the COBRA tool is best utilized as a screening

tool not a quantitative estimation of air quality impacts and (2) the inputs for any model should be

well vetted for accuracy. In addition, for any tool the Commission does adopt, a central value

should be used, not the high end of the range, as proposed by Staff.

The COBRA methodology simplifies the value of air quality changes to be used as a

screening tool as repeatedly cited in the USEPA's user manual. For example, COBRA can help

compare two measures to determine which of those two measures would have a greater impact on

air quality. While COBRA does provide an estimate value of air quality impact, the USEPA

notes that there are other modeling approaches that provide “a more refined picture of the health

and economic impacts of changes in emissions.”21/ The Commission should explore other options

that could provide a more accurate estimation of air quality impacts.

In addition to tool selection, the Commission also needs to further study the avoided

criteria pollutant emission inputs to the tools. As noted in the Amended Staff Proposal, the

COBRA tool inputs were updated to better reflect the current state of California. However, the

avoided emission inputs should be further vetted to ensure the accuracy of the data used to

21/ “User Manual for the Co-Benefits Risk Assessment Health Impacts Screening and Mapping Tool

(COBRA),” Version 3.1, p. 5.

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calculate the air quality impacts. For example, the USEPA’s Emissions & Generation Resource

Integrated Database, emissions from Pebbly Beach (located on Santa Catalina Island) indicate that

the facility emits more than 1,000 tons of NOx emissions per year.22/ However, reported

emissions to ARB indicate that facility emits 50-70 tons per year.23/ This underscores the need

for accurately estimating the avoided criterial pollutant emissions that are inputs to both COBRA

and BenMAP tools.

Any air quality adder utilized should also have hourly granularity so that it can properly

reflect the avoidance of additional air pollution during periods of system peak, when less efficient

peaking plants are dispatched for system reliability. It should also reflect that no air pollutant

emissions are avoided during hours when non-emitting resources are on the margin, such as

periods of renewable curtailment.

To address these points, the Joint Utilities propose that the Commission start a set of

workshops or working team meetings with stakeholders to determine the appropriate model(s) and

inputs necessary to calculate an air quality adder. Of note, the Joint Utilities recommend that the

Commission engage California’s own experts in air quality issues such as ARB and South Coast

Air Quality Management District to provide advice on estimating the impacts of air quality

associated only with the production of electricity.

10. Explain why the Commission should or should not authorize Staff to

continue to study and analyze improvements to the distributed energy

resources cost-effectiveness framework, including the development of a

common resource valuation method, and issue reports on its findings and

subsequent proposals. Are there additional improvements that should be

considered?

Yes, it is reasonable for Staff to continue studying improvements to the DER cost-

effectiveness framework. This includes development of a common resource valuation

methodology (“CRVM”); better alignment with IRP, as outlined in the response to Question No. 6

22/ https://www.epa.gov/sites/production/files/2018-02/egrid2016_data.xlsx

23/ https://www.arb.ca.gov/ei/tools/pollution_map/

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(this should ideally be done prior to adoption of modified versions of the tests); and the additional

improvements suggested below. However, the CRVM is also in scope in the IRP proceeding and

work on this framework should be conducted primarily in the IRP to ensure consistency with

technology neutral evaluation and robust stakeholder participation.

Process improvements: D.16-06-007 allows minor updates to the avoided cost calculator

to be approved through a Commission Resolution. However, major updates, defined as “major

changes to the list of data inputs, addition or deletion of categories or types of avoided costs, or

modifications of the methods or models used in the calculator,”24/ require a petition for a new

rulemaking. A new rulemaking is a large undertaking and would take a long time to resolve. The

requirement for a new rulemaking is also not optimal for changes to the calculator (major updates)

while the current proceeding is still open. The Joint Utilities suggest that the requirement in

D.16-06-067 be modified to allow a petition for modification of a Commission decision to be

filed, which would result in a more expeditious resolution of an issue and allow timelier updates

to the calculator.

Methodology improvements: The Joint Utilities suggest undertaking the following

additional improvements to the ACC model. These have been ordered by importance and ease of

incorporation into the model.

IRP alignment: Improvements as outlined in response to Question No. 6, which

seek to align avoided cost assumptions between the IRP and IDER ACC model.

Marginal emissions rate updates per Self Generation Incentive Program (“SGIP”)

evaluation: The 2016 SGIP Energy Storage Evaluation identified more accurate

marginal emissions rates than used in the current ACC model.25/ The more

accurate methodology used real-time market price curve data (as opposed to the

24/ D.16-06-007, pp. 8-9.

25/ See Appendix A.3 to the 2016 SGIP Advanced Energy Storage Impact Evaluation, Itron, August

31, 2017, pages A-11 – A-13, available at:

http://www.cpuc.ca.gov/WorkArea/DownloadAsset.aspx?id=6442454964.

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day-ahead market approach used in the current ACC model). This more accurate

approach should be incorporated into the ACC model as part of the 2018 ACC

model update.

Heat rate profiles post-2020: The current version of the calculator assumes an

increase in hours of curtailment until 2020 (to 500 hours). This is held constant

however after 2020. The next update should account for a reasonable increase in

the number of hours post-2020. For instance, the Location Net Benefits Analysis

("LNBA”) Working Group has recommended using IRP modeling results

(RESOLVE or another long-term production simulation model) to help shape

long-term energy prices. If using the IRP’s $150/ton value, the system should

reflect the IRP Reference System Plan used to produce that value.

Types of capacity: Decompose capacity into generic, local, and flexible capacity.

Flexible capacity was modeled in a simple fashion in E3’s Distribution Resources

Plan (“DRP”) Demo B LNBA tool, and the DRP LNBA Working Group has

offered local generation capacity recommendations in their final report.

III. CONCLUSION

The Joint Utilities appreciate this opportunity to submit opening comments on the

Amended Staff Proposal and request the Commission to adopt the recommendations contained

herein.

Dated: April 20, 2018

Respectfully submitted on behalf of the Joint Utilities,

By: /s/ Mary A. Gandesbery

MARY A. GANDESBERY

Law Department

77 Beale Street, B30A

San Francisco, CA 94120

Telephone: (415) 973-0675

Facsimile: (415) 973-5520

E-mail: [email protected]

Attorney for

PACIFIC GAS AND ELECTRIC COMPANY