before the public utilities commission of the … · modified trc and pac tests as replacements for...
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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
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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.
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.
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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.
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(“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.
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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.
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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
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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).
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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.
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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.
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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.
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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.
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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.
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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
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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